**Exhibit 99.1**

 

**ANNUAL INFORMATION FORM**

** **

**For the Fiscal Year Ended December 31,2008**

 

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**ARC Energy Trust**

 

**2008 AnnualInformation Form**

 

**March 18, 2009**

 

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** **

**TABLE OF CONTENTS**

** **
| ** **                                                       | **Page** |
|------------------------------------------------------------------|----------|
|                                                             |     |
| GLOSSARY OF TERMS                                                | 1        |
| SPECIAL NOTES TO READER                                          | 2        |
| Regarding Forward Looking  Statements                            | 2        |
| Access to Documents                                              | 3        |
| Abbreviations and Conversions                                    | 3        |
| ARC ENERGY TRUST                                                 | 4        |
| General                                                          | 4        |
| General Development of Our  Business                             | 4        |
| Recent Developments                                              | 4        |
| OUR BUSINESS                                                     | 5        |
| Overview                                                         | 5        |
| Federal Tax Changes for Income  Trusts and Corporations          | 5        |
| Our Organizational Structure                                     | 6        |
| Management Policies                                              | 7        |
| Distributions and Distribution  Policy                           | 7        |
| Capital Expenditures                                             | 7        |
| Potential Acquisitions                                           | 8        |
| STATEMENT OF RESERVES DATA AND OTHER OIL  AND GAS INFORMATION    | 8        |
| Disclosure of Reserves Data                                      | 8        |
| Reserves Data (Forecast Prices  and Costs)                       | 8        |
| Definitions and Notes to  Reserves Data Tables                   | 10       |
| Reserves Categories                                              | 11       |
| Levels of Certainty for Reported  Reserves                       | 12       |
| Reconciliations of Changes in  Reserves                          | 14       |
| Additional Information Relating  to Reserves Data                | 15       |
| Other Oil and Gas Information                                    | 16       |
| Marketing Arrangements                                           | 23       |
| SHARE CAPITAL OF ARC RESOURCES                                   | 24       |
| Common Shares                                                    | 24       |
| Exchangeable Shares                                              | 24       |
| Second Preferred Shares                                          | 25       |
| OTHER INFORMATION RELATING TO OUR BUSINESS                       | 25       |
| Borrowing                                                        | 25       |
| OUR INFORMATION                                                  | 26       |
| Trust Units                                                      | 26       |
| Special Voting Unit                                              | 26       |
| The Trust Indenture                                              | 26       |
| Trustee                                                          | 27       |
| Distributions and Allocations of  Trust Income                   | 27       |
| Future Offerings                                                 | 27       |
| Meetings and Voting                                              | 27       |
| Our Management                                                   | 28       |
| Limitation on Non-Resident  Ownership                            | 28       |
| Right of Redemption                                              | 28       |
| Termination of the Trust                                         | 29       |
| Reporting to Unitholders                                         | 29       |
| Distribution Reinvestment and  Optional Trust Unit Purchase Plan | 29       |
| CORPORATE GOVERNANCE                                             | 29       |
| General                                                          | 29       |
| Trust Indenture                                                  | 29       |

 

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| Decision Making                                                                                          | 30 |
|----------------------------------------------------------------------------------------------------------|----|
| Board of Directors of ARC  Resources                                                                     | 30 |
| AUDIT COMMITTEE DISCLOSURES                                                                              | 34 |
| Members of the Audit Committee                                                                           | 34 |
| Principal Accountant Fees and  Services                                                                  | 34 |
| CONFLICTS OF INTEREST                                                                                    | 35 |
| INTEREST OF MANAGEMENT AND OTHERS IN  MATERIAL TRANSACTIONS                                              | 36 |
| DISTRIBUTIONS TO UNITHOLDERS                                                                             | 36 |
| PRICE RANGE AND TRADING VOLUME OF TRUST  UNITS AND EXCHANGEABLE SHARES                                   | 36 |
| INDUSTRY REGULATIONS                                                                                     | 37 |
| Pricing and Marketing - Oil and  Natural Gas                                                             | 37 |
| Pipeline Capacity                                                                                        | 38 |
| The North American Free Trade  Agreement                                                                 | 38 |
| Provincial Royalties and  Incentives                                                                     | 38 |
| Land Tenure                                                                                              | 42 |
| Environmental Regulation                                                                                 | 43 |
| RISK FACTORS                                                                                             | 45 |
| Volatility of Oil and Natural  Gas Prices                                                                | 45 |
| Variations in Interest Rates and  Foreign Exchange Rates                                                 | 46 |
| Global Financial Crisis                                                                                  | 46 |
| Refinancing Risk and Debt  Service                                                                       | 47 |
| Capital Markets                                                                                          | 47 |
| Third Party Credit  Risk                                                                                 | 48 |
| Maintenance of Distributions                                                                             | 48 |
| Regulatory                                                                                               | 48 |
| Changes in Legislation                                                                                   | 48 |
| Reserves and Resource Estimates                                                                          | 49 |
| Federal Tax Changes for Income  Trusts and Corporations                                                  | 50 |
| Operational Matters                                                                                      | 51 |
| Allocations of Trust Income                                                                              | 51 |
| Purchase of Properties                                                                                   | 51 |
| Enhanced Oil Recovery                                                                                    | 52 |
| Project Risks                                                                                            | 52 |
| Expansion of Operations                                                                                  | 52 |
| Failure to Realize Anticipated  Benefits of Acquisitions and Dispositions                                | 53 |
| Non-resident Ownership of Trust  Units                                                                   | 53 |
| Environmental Concerns                                                                                   | 53 |
| Competition                                                                                              | 54 |
| Accounting Write-Downs as a  Result of GAAP                                                              | 54 |
| Reliance on Key Members of  Management                                                                   | 55 |
| Depletion of Reserves                                                                                    | 55 |
| Net Asset Value                                                                                          | 55 |
| Return of Capital and Right of  Redemption                                                               | 56 |
| Nature of Trust Units                                                                                    | 56 |
| Unitholder Limited Liability                                                                             | 56 |
| Title to Properties                                                                                      | 57 |
| Additional Risk  Factors Applicable to Residents of the United States and Other Non-Residents  of Canada | 57 |

 

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| TRANSFER AGENTS AND REGISTRARS | 58 |
|--------------------------------|----|
| MATERIAL CONTRACTS             | 58 |
| INTEREST OF EXPERTS            | 59 |
| ADDITIONAL INFORMATION         | 59 |

 
| APPENDIX A   -   REPORT  ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR       |
|---------------------------------------------------------------------------------------------------------------------------|
| APPENDIX B   -   REPORT  OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION |
| APPENDIX C   -   MANDATE  OF THE AUDIT COMMITTEE                                            |

 

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**GLOSSARY OF TERMS**

** **

In thisAnnual Information Form, capitalized terms shall have the meanings set forthbelow:

 

**ARC**, **we**, **us**,**our** or **Trust** means ARC Energy Trust and all its controlled entitiesas a consolidated body;

 

**ARC Resources** means ARCResources Ltd.;

 

**ARC Sask** means ARC Oil &Gas Fund, an Alberta trust;

 

**ARC Subco** means 1405292Alberta Ltd., or such other corporation as may be substituted for ARC Subco;

 

**Discovered Petroleum Initially In Place** means the quantity of hydrocarbons that are estimated to be inplace within a known accumulation. Discovered Petroleum Initially In Place is divided into recoverable andunrecoverable portions, with the estimated future recoverable portionclassified as reserves and contingent resources;

 

**Dawson West Area** means ourlands west of the Dawson area in north eastern British Columbia comprised ofthe Sunrise, Sundown, Sunset, Saturn and Monias areas;

 

**Exchangeable Shares** meansthe exchangeable shares of ARC Resources that are exchangeable for Trust Units;

 

**Exchange Ratio**means theratio at which the Exchangeable Shares may be exchanged for Trust Units;

 

**GLJ** means GLJ PetroleumConsultants Ltd., independent petroleum consultants of Calgary, Alberta;

 

**GLJ Report** means thereport prepared by GLJ dated February 19, 2009 evaluating the crude oil,natural gas, natural gas liquids and sulphur reserves attributable to theproperties at December 31, 2008;

 

**Long Term Notes** means theunsecured long term notes issued by ARC Resources to the Trust from time totime bearing interest at rates per annum ranging from 11.25 per cent to 13 percent payable monthly with maturity dates of 15 years from the date of issuance;

 

**Royalties** means,collectively, the royalties payable by ARC Resources to the Trust pursuant tothe royalty agreements which equals 99 per cent of royalty income;

 

**Tax Act** means the *Income Tax Act* (Canada);

 

**Trust Indenture** means thetrust indenture between Computershare Trust Company of Canada, as trustee, andARC Resources Ltd., as amended and restated as of May 15, 2006;

 

**Trust Units** means theunits of the Trust, each unit representing an equal undivided beneficialinterest in the Trust;

 

**TSX** means the TorontoStock Exchange; and

 

**Unitholders** means holdersof Trust Units of the Trust.

 

Certainother terms used in this Annual Information Form but not defined hereinare defined in NI 51-101 and, unless the context otherwise requires, shall havethe same meanings herein as in NI 51-101.

 

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**SPECIAL NOTES TO READER**

** **

**RegardingForward Looking Statements**

** **

Certainstatements contained in this Annual Information Form, and in certain documentsincorporated by reference into this Annual Information Form, constituteforward-looking statements.  Thesestatements relate to future events or our future performance.  All statements other than statements ofhistorical fact may be forward-looking statements.  Forward-looking statements are often, but notalways, identified by the use of words such as “seek”, “anticipate”, “budget”, “plan”,“continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”, “predict”,“potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” andsimilar expressions.  These statementsinvolve known and unknown risks, uncertainties and other factors that may causeactual results or events to differ materially from those anticipated in suchforward-looking statements.  We believethe expectations reflected in those forward-looking statements are reasonablebut no assurance can be given that these expectations will prove to be correctand such forward-looking statements included in, or incorporated by referenceinto, this Annual Information Form should not be unduly relied upon.  These statements speak only as of the date ofthis Annual Information Form or as of the date specified in the documentsincorporated by reference into this Annual Information Form, as the case maybe.

 

Inparticular, this Annual Information Form, and the documents incorporated byreference, contain forward-looking statements pertaining to the following:

 
| · |   | the  performance characteristics of our oil and natural gas properties;                                                        |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------|
| · |   | oil  and natural gas production levels;                                                                                        |
| · |   | the  size of the oil and natural gas reserves and resources;                                                                   |
| · |   | projections  of market prices and costs;                                                                                       |
| · |   | expectations  regarding the ability to raise capital and to continually add to reserves  through acquisitions and development; |
| · |   | treatment  under governmental regulatory regimes and tax laws; and                                                             |
| · |   | capital  expenditures programs.                                                                                                |

 

Theactual results could differ materially from those results anticipated in theseforward-looking statements as a result of the risk factors set forth below andelsewhere in this Annual Information Form:

 
| · |   | volatility  in market prices for oil and natural gas;                                                                                                                                 |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · |   | changes  in foreign exchange rates;                                                                                                                                                   |
| · |   | uncertainties  relating to the weakened global economic situation and consequential  restricted access to capital, increased borrowing costs and refinancing risk  for existing debt; |
| · |   | liabilities  inherent in oil and natural gas operations;                                                                                                                              |
| · |   | uncertainties  associated with estimating oil and natural gas reserves and resources;                                                                                                 |
| · |   | risks  and uncertainties inherent in exploration and development activities;                                                                                                          |
| · |   | competition  for, among other things, capital, acquisitions of reserves, undeveloped lands  and skilled personnel;                                                                    |
| · |   | incorrect  assessments of the value, or failure to realize the anticipated benefits, of  acquisitions;                                                                                |
| · |   | geological,  technical, drilling and processing problems;                                                                                                                             |
| · |   | changes  in income tax laws or changes in tax or environmental laws and incentive  programs or royalty regimes relating to the oil and gas industry and income  trusts; and           |
| · |   | the  other factors discussed under “*Risk  Factors*”.                                                                                                                       |

 

Theactual results could differ materially from those results anticipated in theseforward-looking statements, which are based on assumptions, including as to themarket prices for oil and natural gas; the continuation of the present policiesof the Board of Directors of ARC Resources relating to management of ARC, anddistributions, capital expenditures and other matters; the continued availabilityof capital, acquisitions of reserves, undeveloped lands and skilled personnel;the continuation of the current tax and regulatory regime and other assumptionscontained in this Annual Information Form.

 

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Statementsrelating to “reserves” or “resources” are deemed to be forward-lookingstatements, as they involve the implied assessment, based on certain estimatesand assumptions, that the resources and reserves described can be profitablyproduced in the future.

 

Readersare cautioned that the foregoing lists of factors are not exhaustive.  The forward-looking statements contained inthis Annual Information Form and the documents incorporated by referenceherein are expressly qualified by this cautionary statement.  We do not undertake any obligation topublicly update or revise any forward-looking statements except as required bysecurities laws or regulations.

 

**Accessto Documents**

** **

Anydocument referred to in this Annual Information and described as being filed onSEDAR at www.sedar.com (including those documents referred to as beingincorporated by reference in this Annual Information Form) may be obtained freeof charge from us at 2100, 440 — 2nd Avenue S.W., Calgary, Alberta, T2P 5E9.

 

**Abbreviationsand Conversions**

 
| bbl    |   | Barrel                                                                                                                                     |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------|
| bbl/d  |   | barrels per day                                                                                                                            |
| Bcf    |   | billion cubic feet                                                                                                                         |
| boe    |   | barrels of oil equivalent  converting 6 Mcf of natural gas or one barrel of natural gas liquids to  one barrel of oil equivalent |
| boe/d  |   | barrels of oil equivalent  per day                                                                                                    |
| Mbbl   |   | one thousand barrels                                                                                                                       |
| mboe   |   | one thousand barrels of  oil equivalent                                                                                                    |
| Mcf    |   | one thousand cubic feet                                                                                                                    |
| Mcfpd  |   | one thousand cubic feet  per day                                                                                                           |
| MMBTU  |   | one million British  Thermal Units                                                                                                         |
| MMcf   |   | one million cubic feet                                                                                                                     |
| MMcfpd |   | one million cubic feet per  day                                                                                                            |
| $MM    |   | one million dollars                                                                                                                        |
| MMbbl  |   | one million barrels                                                                                                                        |
| NGLs   |   | natural gas liquids                                                                                                                        |
| Tcf    |   | one trillion cubic feet                                                                                                                    |

 

We haveadopted the standard of 6 Mcf:1boe when converting natural gas to boes.  Boes may be misleading, particularly if usedin isolation.  A boe conversion ratio of6 Mcf per barrel is based on an energy equivalency conversion method primarilyapplicable at the burner tip and does not represent a value equivalency at thewellhead.

 

Thefollowing table sets forth certain standard conversions between StandardImperial Units and the International System of Units (or metric units).

 
| **To Convert From** | ** ** | **To**       | ** ** | **Multiply By** | ** ** |
|---------------------|------------|--------------|------------|-----------------|------------|
| cubic metres        |       | cubic feet   |       | 35.315          |       |
| bbls                |       | cubic metres |       | 0.159           |       |
| cubic metres        |       | bbls         |       | 6.290           |       |
| Feet                |       | metres       |       | 0.305           |       |
| Metres              |       | feet         |       | 3.281           |       |
| Miles               |       | kilometres   |       | 1.609           |       |
| Kilometres          |       | miles        |       | 0.621           |       |
| Acres               |       | hectares     |       | 0.4047          |       |
| Hectares            |       | acres        |       | 2.471           |       |

 

Alldollar amounts set forth in this Annual Information Form are in Canadiandollars, except where otherwise indicated.

 

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**ARC ENERGY TRUST**

** **

**General**

** **

We arean open-end investment trust created on May 7, 1996 under the laws of theProvince of Alberta pursuant to the Trust Indenture.  Computershare Trust Company of Canada hasbeen appointed as trustee under the Trust Indenture.  The beneficiaries of the Trust are holders ofthe Trust Units.  The principal and headoffice of the Trustee is located at Suite 600, 530 8th Avenue SW., Calgary, Alberta,T2P 3S8.  The Trust Indenture hasbeen amended from time to time, the latest amendments being approved at theannual and special meeting of Unitholders held on May 15, 2006.

 

Theprincipal offices of the Trust and ARC Resources are located at 2100, 440 — 2nd Avenue S.W., Calgary,Alberta, T2P 5E9 and its registered office is located at 1400, 350 — 4th Avenue S.W., Calgary,Alberta, T2P 3N9.

 

Thefollowing are the names, the percentage of voting securities and thejurisdiction governing our material****subsidiariesand trusts, either direct or indirect, as at December 31, 2008:

 
| ** **         | ** ** | **Percentage of voting  securities  (directly or indirectly)** | ** ** | **Nature of Entity** | ** ** | **Jurisdiction of  Incorporation/  Formation** |
|--------------------|------------|----------------------------------------------------------------|------------|----------------------|------------|------------------------------------------------|
| ARC Resources Ltd. |       | 100%                                                           |       | Corporation          |       | Alberta                                        |

 

**GeneralDevelopment of Our Business**

** **

Adescription of the general development of our business over the last threefinancial years follows.

 

In2006, we incurred capital expenditures of $496.3 million, of which $312.5million (63 per cent) was development and facility capital expenditures, $115.2million (23 per cent) was property acquisitions costs net of disposition andproperty swaps and $49.4 million (10 per cent) was costs of lands acquired,geological and geophysical, and drilling costs for 2006 exploration wellsdrilled.  We completed one corporateacquisition for total consideration of $16.6 million resulting in totalacquisitions, net of dispositions, of $131.8 million in the year.  We also distributed $484.2 million toUnitholders in 2006.

 

In2007, we incurred capital expenditures of $439.7 million, of which $281.4million (64 per cent) was development and facility capital expenditures, $42.5million (10 per cent) was property acquisitions costs net of dispositions and$112.5 million (26 per cent) was costs of lands acquired, geological andgeophysical, and drilling costs for 2007 exploration wells drilled.  Included in these costs was the purchase ofundeveloped land located primarily in the Dawson and Dawson West Area ofBritish Columbia through Crown mineral sales for $77.5 million.  We also distributed $498 million toUnitholders in 2007.

 

In2008, we incurred capital expenditures of $599.6 million, of which $371.1million (62 per cent) was development and facility capital expenditures, $51million (nine per cent) was property acquisitions costs net of dispositions and$164.1 million (27 per cent) was costs of lands acquired, geological andgeophysical, and drilling costs for 2008 exploration wells drilled.  Included in these costs was the purchase ofundeveloped acreage through Crown mineral sales for $122.4 million, of which$80.3 million was expended in the Dawson and Dawson West Area of BritishColumbia.  We also distributed $570million to Unitholders in 2008.

 

EffectiveJanuary 1, 2008, we completed an internal reorganization wherein, amongother things, all of ARC Sask’s assets were transferred to ARC Resources andthe royalty agreements between each of ARC Resources and ARC Sask and the Trustwere exchanged for a new royalty agreement between ARC Resources and theTrust.  In addition, the obligationsunder the Long Term Note from ARC Sask to the Trust were assumed by ARCResources.

 

**RecentDevelopments**

** **

On January 12, 2009, we announced that in light of the continuingweak commodity price environment and the increasing disparity between U.S. andCanadian oil prices, the cash distribution payable on February 16, 2009 toUnitholders of record on January 30, 2009 will be reduced from $0.15 perTrust Unit to $0.12 per Trust Unit.  We 

 

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also announced the reduction of our previously announced 2009 capitalprogram from approximately $585 million to approximately $450 million through areduction of certain capital costs and the deferral of certain capital spendinginto the first quarter of 2010.

 

On February 6,2009, the Trust closed an equity offering to issue 15.5 million trust units at$16.35 per unit.  The net proceeds of thetransaction were $240 million and were used to reduce the Trust’s indebtedness.

 

On February 11,2009, Myron M. Stadnyk was appointed as President and Chief Operating Officerof ARC Resources.  John P. Dielwartcontinues as Chief Executive Office of ARC Resources.

 

**OUR BUSINESS**

** **

**Overview**

** **

Ourprincipal undertaking is to receive Royalties and other income on petroleum andnatural gas properties and related assets and to acquire and hold securities ofsubsidiaries, trusts and partnerships. Our subsidiaries, trusts and partnerships are entitled to carry on awide scope of energy related activities including the business of acquiring, developing,exploiting and disposing of all types of energy business related assets, whichincludes petroleum and natural gas related assets, oil sands interests,electricity or power generating assets and pipeline, gathering, processing andtransportation assets.  To date the Trust’sbusiness has been focused to the acquisition and development of oil and naturalgas reserves in Western Canada.  We issueTrust Units and may also issue securities of ARC Resources or an affiliate ofARC Resources which are exchangeable for Trust Units and confer voting rightsin us.

 

Ourprincipal investments are the Royalties granted by ARC Resources, the commonshares of ARC Resources and the Long Term Notes.  The Royalties consist of a 99 per cent shareof royalty income on all of the properties held by ARC Resources.  Royalty income is generally all productionrevenue less all operating and capital costs and all debt service chargesincluding principal repayments.  On eachmonthly distribution date, ARC Resources pays the Trust 99 per cent of royaltyincome and ARC Resources pays interest on outstanding Long Term Notes.  The Trust will make distributions of suchfunds, subject only to the required deductions and its expenses.  Such distributions may be wholly or in parttaxable.  See “Distributions toUnitholders”.

 

We arestructured with the objective of having income tax incurred only in the handsof Unitholders.  Income distributed toUnitholders consists essentially of cash flow from operating activitiesgenerated by our oil and natural gas properties.  More specifically, internally generated cashflow from operating activities, with the exception of such cash flow used forcapital expenditures, reclamation fund contributions, interest expense, debtrepayments, income taxes not passed on to Unitholders, and working capitalrequirements, is effectively returned to Unitholders.

 

As anopen-ended investment, Unitholders have a right to redeem their TrustUnits.  As with most other open-endedfunds, it is anticipated that trading on the TSX and not the right of retractionwould continue as the primary mechanism for Unitholders to sell their TrustUnits.  For more detailed informationregarding the right of redemption, see “Our Information - Right of Redemption”.

 

As at December 31,2008, we had approximately 496 employees and full time consultants.

 

**FederalTax Changes for Income Trusts and Corporations**

** **

On June 22,2007, the federal legislation (Bill C-52) implementing the tax on publiclytraded income trusts and limited partnerships (the “**SIFT Rules**”) received Royal Assent.  The SIFT Rules are not expected toeffect the Trust until 2011 provided the Trust does not exceed the normalgrowth guidelines announced by the Department of Finance.  Subsequent to the February 6, 2009equity issuance, the Trust can increase its equity by approximately $5.1billion before 2011 without exceeding the normal growth guidelines. The Trustdoes not anticipate that the normal growth guidelines will impair the Trust’sability to annually replace or grow reserves in the next two years as theguidelines allow sufficient growth targets.

 

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Underthe SIFT Rules, the SIFT tax rate will be the federal general corporate incometax rate and the applicable provincial corporate rate. The federal generalcorporate income tax rate will be 16.5 per cent in 2011 and 15 per cent after2011 and the provincial component will be 10 per cent.

 

TheMinister of Finance has tabled a Notice of Ways and Means which includeslegislation facilitating the conversion of existing income trusts intocorporations on a tax neutral basis.

 

Managementand the Board of Directors continue to review the impact of the SIFT Rules onour business strategy and while there has not been a decision as to ARC’sfuture direction at this time we are currently of the view that the conversionfrom a trust to a corporation may be the most logical and tax efficientalternative for Unitholders.   Canadianinvestors who hold their Trust Units in a taxable account will be relativelyindifferent on an after tax basis as to whether ARC is structured as acorporation or as a trust in 2011. However, Canadian tax deferred investors (those holding their TrustUnits in a tax deferred vehicle such as an RRSP, RRIF or pension plan) andforeign investors will realize a lower return on distributions in 2011 due tothe introduction of the SIFT tax that would apply should we remain a trust andtheir inability to claim the dividend tax credit if we convert to acorporation.

 

Formore information, see “Risk Factors — Federal Tax Changes for Income Trusts andCorporations” and “Risk Factors — Changes in Legislation”.

 

**OurOrganizational Structure**

 

Ourstructure and the flow of cash from ARC Resources to the Trust as of December 31,2008 are set forth below:

 

 

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Notes:
| (1) |   | As at  December 31, 2008, properties in British Columbia are held by ARC  Petroleum Inc. as trustee and agent of ARC Resources.                                   |
|-----|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) |   | ARC  Resources had a total of 1,091,414 Exchangeable Shares outstanding as at  December 31, 2008 that were exchangeable for approximately 2,746,740  Trust Units. |

 

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**ManagementPolicies**

** **

All ouractivities are directed towards maximizing value creation for Unitholders. Thisis achieved through a combination of investing capital to enhance the value ofour assets, operating our producing oil and gas properties in a low cost mannerto maximize the recovery of reserves, and through making monthly distributionsto our Unitholders.  We direct ourefforts to increase the value of our assets through development drilling andassociated development activities and enhanced oil recovery activities as wellas by the periodic acquisition of undeveloped and producing oil and gasproperties.  We acquire oil and naturalgas producing properties and primarily participate in development activitiesthat are generally considered to be of a low risk nature in the oil and gasindustry.  Also, a percentage of eachyear’s capital budget will be devoted to moderate risk development and lowerrisk exploration opportunities on our properties.  Recently, we have undertaken a moresubstantial program of purchasing undeveloped land, particularly in the Dawsonarea of north-eastern British Columbia, where we have spent approximately $250million since January 1, 2006.

 

We havepolicies for the hiring, training and development of staff to provide the inhouse expertise to fully exploit ARC’s assets. In addition, we have specific health and safety policies which set outprocedures, practices and reporting of actions to assist in ensuring that ARCemployees and contractors employ safety measures and act in a safe and prudentmanner.  We also have policies whichencompass the cleanup, abandonment and site reclamation activities of ARC.

 

**Distributionsand Distribution Policy**

** **

Distributionsare made on the 15th day (or if such date is not a business day, onthe next business day) following the end of each calendar month to Unitholdersof record on the last business day of each such calendar month.

 

TheBoard of Directors of ARC Resources on behalf of the Trust reviews thedistribution policy from time to time. The actual amount distributed is at the discretion of the Board ofDirectors and is principally dependent upon the commodity price environment andthe amount of cash flow from operating activities utilized to fund the Trust’scapital expenditure program and the annual contribution to the Trust’sreclamation fund.  In times of highcommodity prices, we withhold a greater percentage of cash flow from operatingactivities so that more of the capital program can be funded internally.

 

Historically,ARC has strived for stability in distributions and has announced distributionlevels on a quarterly basis.  Duringtimes of extreme commodity price volatility, such as those we are currentlyexperiencing, the distributions are reviewed on a monthly basis and adjusted asrequired.

 

See “RiskFactors — Maintenance of Distributions”.

 

**CapitalExpenditures**

** **

We mayapprove future capital expenditures or farmouts under the terms of the royaltyagreement.  Future capital expenditureson the properties will generally be of the type that are****intended to maintain or improve productionfrom the properties.  We may financecapital expenditures from production revenues, the proceeds of the issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, borrowings, farmouts or with working capital.

 

We mayacquire additional properties and related tangible equipment and fund suchacquisitions from production revenues, the net proceeds of any issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, or from borrowings, farmouts or with workingcapital.  We may sell any of ourinterests in properties and release the Royalties from such properties inconsideration of the allocation of a portion of the proceeds to the Trust.  In connection with the sale of any interestsin the properties, we will determine whether the net proceeds of the saleshould be reinvested in additional properties, used to repay borrowings or makecapital expenditures in ARC Resources or be distributed to Unitholders.

 

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**PotentialAcquisitions**

** **

Wecontinue to evaluate potential acquisitions of all types of petroleum andnatural gas and other energy-related assets as part of our ongoing acquisitionprogram.  We are normally in the processof evaluating several potential acquisitions at any one time which individuallyor together could be material.  We cannotpredict whether any current or future opportunities will result in one or moreacquisitions.

 

**STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION**

** **

Thestatement of reserves data and other oil and gas information is set forth below(the “**Statement**”).  The effective date of the Statement is December 31,2008 and the preparation date of the Statement is January 16, 2009.  The Report of Management and Directors onReserves Data and Other Information on Form 51-101F3 and the Report onReserves Data by GLJ on Form 51-102F2 are attached as Appendices A and Bto this Annual Information Form.

 

**Disclosureof Reserves Data**

** **

Thereserves data set forth below is based upon an evaluation by GLJ with aneffective date of December 31, 2008 contained in the GLJ Report dated February 19,2009.  The reserves data summarizes ouroil, liquids and natural gas reserves and the net present values of future netrevenue for these reserves using forecast prices and costs prior to provision forinterest, general and administrative expenses, the impact of any hedgingactivities or the liability associated with certain abandonment and well,pipeline and facilities reclamation costs which were not deducted by GLJ inestimating future net revenue.  Futurenet revenues have been presented on a before and after tax basis.  The reserves data conforms with therequirements of NI 51-101.  We engagedGLJ to provide an evaluation of proved and proved plus probable reserves.  See also “Definitions and Notes to ReservesData Tables” below.

 

All ofour reserves are in Canada and, specifically, in the provinces of Alberta,British Columbia, Saskatchewan and Manitoba.

 

**It should not be assumed that the estimates of future netrevenues presented in the tables below represent the fair market value of thereserves.  There is no assurance that theforecast prices and costs assumptions will be attained and variances could bematerial.  The recovery and reservesestimates of crude oil, natural gas liquids and natural gas reserves providedherein are estimates only and there is no guarantee that the estimated reserveswill be recovered.  Actual crude oil,natural gas and natural gas liquid reserves may be greater than or less thanthe estimates provided herein.  Readersshould review the definitions and information contained in “Definitions andNotes to Reserves Data Tables” in conjunction with the following tables andnotes.  For more information as to therisks involved, see “Risk Factors — Reserves and Resource Estimates” and “RiskFactors — Volatility of Oil and Natural Gas Prices”.**

 

**ReservesData (Forecast Prices and Costs)**

** **

SUMMARY OF OIL AND GAS RESERVESAND NET PRESENT VALUES OF FUTURE NET REVENUEas of December 31, 2008FORECAST PRICES AND COSTS

 
| ** **                  | ** ** | **RESERVES**                            | ** ** |
|-----------------------------|------------|-----------------------------------------|------------|
| ** **                  | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROVED                      |       |                                    |       |   |   |   |   |   |   |
| Developed  Producing        |       | 94,805                                  |       | 80,767 |   | 2,357 |   | 2,370 |   |
| Developed  Non-Producing    |       | 2,187                                   |       | 1,589 |   | 9 |   | 9 |   |
| Undeveloped                 |       | 7,919                                   |       | 6,448 |   | 0 |   | 0 |   |
| TOTAL PROVED                |       | 104,912                                 |       | 88,804 |   | 2,366 |   | 2,379 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                    |       | 30,138                                  |       | 24,921 |   | 640 |   | 599 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 135,049                                 |       | 113,725 |   | 3,006 |   | 2,978 |   |

 

8

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| ** **                  | ** ** | **RESERVES**         | ** ** |
|-----------------------------|------------|----------------------|------------|
| ** **                  | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Bcf)**     | ** ** | **Net  (Bcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                 |       |   |   |   |   |   |   |
| PROVED                      |       |                 |       |   |   |   |   |   |   |
| Developed  Producing        |       | 438                  |       | 382 |   | 8,535 |   | 6,028 |   |
| Developed  Non-Producing    |       | 30                   |       | 22 |   | 521 |   | 352 |   |
| Undeveloped                 |       | 269                  |       | 201 |   | 2,000 |   | 1,467 |   |
| TOTAL PROVED                |       | 737                  |       | 604 |   | 11,057 |   | 7,847 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| PROBABLE                    |       | 263                  |       | 211 |   | 3,330 |   | 2,440 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 1,000                |       | 816 |   | 14,386 |   | 10,287 |   |

 
| ** **                  | ** ** | **RESERVES**      | ** ** |
|-----------------------------|------------|-------------------|------------|
| ** **                  | ** ** | **TOTAL**         | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (mboe)** | ** ** | **Net  (mboe)** | ** ** |
|                        |       |              |       |   |   |
| PROVED                      |       |              |       |   |   |
| Developed  Producing        |       | 178,660           |       | 152,788 |   |
| Developed  Non-Producing    |       | 7,794             |       | 5,603 |   |
| Undeveloped                 |       | 54,700            |       | 41,350 |   |
| TOTAL PROVED                |       | 241,154           |       | 199,742 |   |
|                        |       |              |       |   |   |
| PROBABLE                    |       | 77,960            |       | 63,186 |   |
|                        |       |              |       |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 319,114           |       | 262,928 |   |

 
| ** **                  | ** ** | **NET PRESENT VALUES OF FUTURE NET REVENUE** | ** ** |
|-----------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                  | ** ** | **BEFORE INCOME TAXES DISCOUNTED AT (%/year)**    | ** ** | **AFTER INCOME TAXES DISCOUNTED AT (%/year)** | ** ** |
| **RESERVES  CATEGORY**      | ** ** | **0  (MM$)**                                                               | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** | **0  (MM$)** | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** |
|                        |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROVED                      |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed  Producing        |       | 7,166                                                                      |       | 4,760 |   | 3,605 |   | 2,928 |   | 2,480 |   | 5,933 |   | 4,052 |   | 3,135 |   | 2,589 |   | 2,224 |   |
| Developed  Non-Producing    |       | 277                                                                        |       | 181 |   | 133 |   | 104 |   | 85 |   | 210 |   | 139 |   | 104 |   | 82 |   | 67 |   |
| Undeveloped                 |       | 1,500                                                                      |       | 915 |   | 606 |   | 419 |   | 295 |   | 1,106 |   | 663 |   | 426 |   | 283 |   | 188 |   |
| TOTAL  PROVED               |       | 8,943                                                                      |       | 5,856 |   | 4,344 |   | 3,450 |   | 2,861 |   | 7,248 |   | 4,854 |   | 3,665 |   | 2,953 |   | 2,479 |   |
|                        |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROBABLE                    |       | 3,600                                                                      |       | 1,648 |   | 948 |   | 620 |   | 438 |   | 2,611 |   | 1,196 |   | 687 |   | 448 |   | 316 |   |
|                        |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| TOTAL  PROVED PLUS PROBABLE |       | 12,543                                                                     |       | 7,504 |   | 5,292 |   | 4,070 |   | 3,298 |   | 9,859 |   | 6,050 |   | 4,352 |   | 3,402 |   | 2,795 |   |

 

9

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TOTAL FUTURE NET REVENUE(UNDISCOUNTED)as of December 31, 2008FORECAST PRICES AND COSTS

 
| **RESERVES  CATEGORY**        | ** ** | **REVENUE  (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **ABANDONMENT  AND  RECLAMATION  COSTS  (MM$)** | ** ** | **FUTURE  NET  REVENUE  BEFORE  INCOME  TAXES  (MM$)** | ** ** | **INCOME  TAXES  (MM$)** | ** ** | **FUTURE  NET  REVENUE  AFTER  INCOME  TAXES  (MM$)** | ** ** |
|-------------------------------|------------|--------------------|------------|----------------------|------------|-----------------------------|------------|-------------------------------|------------|-------------------------------------------------|------------|--------------------------------------------------------|------------|--------------------------|------------|-------------------------------------------------------|------------|
|                          |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Reserves               |       | 18,793             |       | 3,292                |       | 5,441                       |       | 872                           |       | 245                                             |       | 8,943                                                  |       | 1,694                    |       | 7,248                                                 |       |
|                          |       |               |       |                 |       |                        |       |                          |       |                                            |       |                                                   |       |                     |       |                                                  |       |
| Proved Plus Probable Reserves |       | 25,891             |       | 4,650                |       | 7,217                       |       | 1,200                         |       | 281                                             |       | 12,543                                                 |       | 2,683                    |       | 9,859                                                 |       |

 

FUTURE NET REVENUEBY PRODUCTION GROUPas of December 31, 2008FORECAST PRICES AND COSTS

 
| **RESERVES CATEGORY**     | ** ** | **PRODUCTION GROUP**  | ** ** | **FUTURE NET  REVENUE  BEFORE  INCOME TAXES  (discounted at  10%/year)  (MM$)** | ** ** | **PER UNIT** | ** ** |
|--------------------------------|------------|----------------------------|------------|------------------------------------------------------------------------------------------------|------------|-------------------|------------|
|                           |       |                       |       |                                                                                           |       |              |       |
| Proved  Reserves               |       | Light and Medium Crude Oil |       | 2,520                                                                                          |       | $                 | 23.79/boe  |   |
|                           |       | Heavy Oil                  |       | 68                                                                                             |       | $                 | 27.28/boe  |   |
|                           |       | Natural Gas                |       | 1,755                                                                                          |       | $                 | 3.21/Mcf   |   |
|                           |       | Total                      |       | 4,344                                                                                          |       |              |       |
|                           |       |                       |       |                                                                                           |       |              |       |
| Proved Plus  Probable Reserves |       | Light and Medium Crude Oil |       | 3,033                                                                                          |       | $                 | 22.46/boe  |   |
|                           |       | Heavy Oil                  |       | 81                                                                                             |       | $                 | 25.93/boe  |   |
|                           |       | Natural Gas                |       | 2,178                                                                                          |       | $                 | 2.92/Mcf   |   |
|                           |       | Total                      |       | 5,292                                                                                          |       |              |       |

 

**Definitionsand Notes to Reserves Data Tables**

 

In thetables set forth above in “Disclosure of Reserves Data” and elsewhere in thisAnnual Information Form the following definitions and other notes areapplicable:

 

1.                                       “**Gross**” means:

 

(a)                                  in relation to our interest in production and reserves, our interest(operating and non-operating) before deduction of royalties and withoutincluding any royalty interest of us;

 

(b)                                 in relation to wells, the total number of wells in which we have aninterest; and

 

(c)                                  in relation to properties, the total area of properties in which wehave an interest.

 

2.                                       “**Net**” means:

 

(a)                                  in relation to our interest in production and reserves, our interest(operating and non-operating) after deduction of royalties obligations, plusour royalty interest in production or reserves;

 

10

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(b)                                 in relation to wells, the number of wells obtained by aggregatingour working interest in each of our gross wells; and

 

(c)                                  in relation to our interest in a property, the total area in whichwe have an interest multiplied by the working interest we owned.

 

3.                                       Columns may not add due to rounding.

 

4.                                       The crude oil, natural gas liquids and natural gas reservesestimates presented in the GLJ Report are based on the definitions andguidelines contained in the Canadian Oil and Gas Evaluation Handbook (COGEHandbook).  A summary of thosedefinitions are set forth below:

 

**ReservesCategories**

** **

Reservesare estimated remaining quantities of oil and natural gas and relatedsubstances anticipated to be recoverable from known accumulations, from a givendate forward, based on analysis of drilling, geological, geophysical andengineering data; the use of established technology; and specified economicconditions.

 

Reservesare classified according to the degree of certainty associated with theestimates.

 

(a)                                  **Proved reserves**are those reserves that can be estimated with a high degree ofcertainty to be recoverable. It is likely that the actual remaining quantitiesrecovered will exceed the estimated proved reserves.

 

(b)                                 **Probable reserves** are those additional reserves that are less certain to be recoveredthan proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plusprobable reserves.

 

Othercriteria that must also be met for the categorization of reserves are providedin the COGE Handbook.

 

Each ofthe reserves categories (proved and probable) may be divided into developed andundeveloped categories:

 

(c)                                  **Developed reserves** are those reserves that are expected to be recovered from existingwells and installed facilities or, if facilities have not been installed, thatwould involve a low expenditure (for example, when compared to the cost ofdrilling a well) to put the reserves on production. The developed category maybe subdivided into producing and non-producing.

 

(i)                                     **Developed producing reserves** are those reserves that are expected to be recovered fromcompletion intervals open at the time of the estimate. These reserves may becurrently producing or, if shut-in, they must have previously been onproduction, and the date of resumption of production must be known withreasonable certainty.

 

(ii)                                  **Developed non-producing reserves** are those reserves that either have not been on production, or havepreviously been on production, but are shut-in, and the date of resumption ofproduction is unknown.

 

(d)                                 **Undeveloped reserves** are those reserves expected to be recovered from knownaccumulations where a significant expenditure (for example, when compared tothe cost of drilling a well) is required to render them capable of production.They must fully meet the requirements of the reserves classification (proved,probable) to which they are assigned.

 

Inmulti-well pools it may be appropriate to allocate total pool reserves betweenthe developed and undeveloped categories or to subdivide the developed reservesfor the pool between developed producing and developed non-producing. Thisallocation should be based on the estimator’s assessment as to the reservesthat will be recovered from specific wells, facilities and completion intervalsin the pool and their respective development and production status.

 

11

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**Levels ofCertainty for Reported Reserves**

** **

Thequalitative certainty levels referred to in the definitions above areapplicable to individual reserves entities (which refers to the lowest level atwhich reserves calculations are performed) and to reported reserves (whichrefers to the highest level sum of individual entity estimates for whichreserves are presented). Reported reserves should target the following levelsof certainty under a specific set of economic conditions:

 

(a)                                  at least a 90 per cent probability that the quantities actuallyrecovered will equal or exceed the estimated proved reserves; and

 

(b)                                 at least a 50 per cent probability that the quantities actuallyrecovered will equal or exceed the sum of the estimated proved plus probablereserves.

 

Aqualitative measure of the certainty levels pertaining to estimates preparedfor the various reserves categories is desirable to provide a clearerunderstanding of the associated risks and uncertainties. However, the majorityof reserves estimates will be prepared using deterministic methods that do notprovide a mathematically derived quantitative measure of probability. Inprinciple, there should be no difference between estimates prepared usingprobabilistic or deterministic methods.

 

Additionalclarification of certainty levels associated with reserves estimates and theeffect of aggregation is provided in the COGE Handbook.

 

5.                                       Forecast prices and costs

 

Theseare prices and costs that are generally acceptable as being a reasonableoutlook of the future as of the evaluation effective date.  To the extent that there are fixed orpresently determinable future prices or costs to which we are legally bound bya contractual or other obligation to supply a physical product, including thosefor an extension period of a contract that is likely to be extended, thoseprices or costs shall be incorporated into the forecast prices.

 

Theforecast cost and price assumptions include increases in wellhead sellingprices and take into account inflation with respect to future operating andcapital costs.  Crude oil, natural gasand natural gas liquids benchmark reference pricing, as at December 31,2008, inflation and exchange rates utilized in the GLJ Report were as follows:

 

12

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SUMMARYOF PRICING AND INFLATION RATE ASSUMPTIONSas of December 31, 2008FORECAST PRICES AND COSTS

 
| ** ** | ** ** | **OIL**       | ** ** | **NATURAL**           | ** ** | **EDMONTON LIQUIDS PRICES** | ** ** | ** **              | ** ** | ** **        |
|------------|------------|---------------|------------|-----------------------|------------|---------------------------------------|------------|-------------------------|------------|-------------------|
| ** ** | ** ** | **WTI**       | ** ** | **Edmonton**          | ** ** | **Hardisty**                          | ** ** | **Cromer**              | ** ** | **GAS**           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** ** | ** ** | **Cushing**   | ** ** | **Par Price**    | ** ** | **Heavy**                             | ** ** | **Medium**              | ** ** | **AECO Gas** | ** ** | ** ** | ** ** | ** ** | ** ** | **Pentanes** | ** ** | **INFLATION** | ** ** | **EXCHANGE** |
| ** ** | ** ** | **Oklahoma**  | ** ** | **40° API** | ** ** | **12° API**                 | ** ** | **29.3° API** | ** ** | **Price**         | ** ** | **Propane** | ** ** | **Butane** | ** ** | **Plus** | ** ** | **RATES****(1)** | ** ** | **RATE****(2)** |
| **Year**   | ** ** | **($US/bbl)** | ** ** | **($Cdn/bbl)**        | ** ** | **($Cdn/bbl)**                        | ** ** | **($Cdn/bbl)**          | ** ** | **($Cdn/MMbtu)**  | ** ** | **($Cdn/bbl)** | ** ** | **($Cdn/bbl)** | ** ** | **($Cdn/bbl)** | ** ** | **%/Year** | ** ** | **($US/$Cdn)** |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| Forecast   |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2009       |       | 57.50         |       | 68.61                 |       | 43.10                                 |       | 59.00                   |       | 7.58              |   | 43.22 |   | 52.14 |   | 69.98 |   | 2 | % | 0.825 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2010       |       | 68.00         |       | 78.94                 |       | 49.76                                 |       | 68.68                   |       | 7.94              |   | 49.73 |   | 61.57 |   | 80.52 |   | 2 | % | 0.850 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2011       |       | 74.00         |       | 83.54                 |       | 54.35                                 |       | 73.52                   |       | 8.34              |   | 52.63 |   | 65.16 |   | 85.21 |   | 2 | % | 0.875 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2012       |       | 85.00         |       | 90.92                 |       | 59.23                                 |       | 80.01                   |       | 8.70              |   | 57.28 |   | 70.92 |   | 92.74 |   | 2 | % | 0.925 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2013       |       | 92.01         |       | 95.91                 |       | 62.54                                 |       | 84.40                   |       | 8.95              |   | 60.42 |   | 74.81 |   | 97.82 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2014       |       | 93.85         |       | 97.84                 |       | 63.82                                 |       | 86.10                   |       | 9.14              |   | 61.64 |   | 76.32 |   | 99.80 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2015       |       | 95.73         |       | 99.82                 |       | 65.13                                 |       | 87.84                   |       | 9.34              |   | 62.89 |   | 77.86 |   | 101.81 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2016       |       | 97.64         |       | 101.83                |       | 66.46                                 |       | 89.61                   |       | 9.54              |   | 64.15 |   | 79.43 |   | 103.87 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2017       |       | 99.59         |       | 103.89                |       | 67.83                                 |       | 91.42                   |       | 9.75              |   | 65.45 |   | 81.03 |   | 105.97 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| 2018       |       | 101.59        |       | 105.99                |       | 69.22                                 |       | 93.27                   |       | 9.95              |   | 66.77 |   | 82.67 |   | 108.10 |   | 2 | % | 0.950 |   |
|       |       |          |       |                  |       |                                  |       |                    |       |              |   |   |   |   |   |   |   |   |   |   |   |
| Thereafter |       | (3)           |       | (3)                   |       | (3)                                   |       | (3)                     |       | (3)               |   | (3) |   | (3) |   | (3) |   | 2 | % | 0.950 |   |

 

----

Notes:

(1)                                  Inflation rates forforecasting prices and costs.

(2)                                  Exchange rates used to generatethe benchmark reference prices in this table.

(3)                                  Prices escalate 2.0 per centper year from 2018.

 

Weightedaverage actual prices realized for the year ended December 31, 2008, were$8.58/Mcf for natural gas, $94.97/bbl for light and medium crude oil, $77.85/bblfor heavy crude oil and $69.71/bbl for natural gas liquids.  Only a minor amount of our production ischaracterized as heavy oil.

 

See “Risk Factors — Reserves and ResourcesEstimates.”

 

6.                                       Future Development Costs

 

The following table sets forth development costsdeducted in the estimation of our future net revenue attributable to thereserves categories noted below.

 
| ** **                     | ** ** | **Forecast Prices and Costs** | ** ** |
|--------------------------------|------------|----------------------------------------------|------------|
| **Year**                       | ** ** | **Proved Reserves  (M$)**               | ** ** | **Proved Plus Probable  Reserves (M$)** | ** ** |
|                           |       |                                         |       |   |   |
| 2009                           |       | 284,922                                      |       | 324,618 |   |
| 2010                           |       | 152,868                                      |       | 193,160 |   |
| 2011                           |       | 126,674                                      |       | 175,751 |   |
| 2012                           |       | 91,065                                       |       | 113,422 |   |
| 2013                           |       | 72,294                                       |       | 89,364 |   |
| Total:  Undiscounted           |       | 871,656                                      |       | 1,199,839 |   |
| Total:  Discounted at 10%/year |       | 666,291                                      |       | 885,996 |   |

 

Weexpect to fund the development costs of the reserves through a combination ofcash flow from operating activities, debt, and the sale of existing assets andthe issuance of Trust Units.

 

Therecan be no guarantee that funds will be available or that we will allocatefunding to develop all of the reserves attributed in the GLJ Report.  Failure to develop those reserves would havea negative impact on future cash flow from operating activities.

 

13

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Theinterest or other costs of external funding are not included in the reservesand future net revenue estimates and would reduce reserves and future netrevenue to some degree depending upon the funding sources utilized.  We do not anticipate that interest or otherfunding costs would make development of any property uneconomic.

 

7.             Estimated futurewell abandonment costs related to reserves wells have been taken into accountby GLJ in determining the   aggregate future net revenue therefrom.

 

8.             Theforecast price and cost assumptions assumed the continuance of current laws andregulations.

 

9.             Allfactual data supplied to GLJ was accepted as represented.  No field inspection was conducted.

 

10.           Theestimates of future net revenue presented in the tables above do not representfair market value.

** **

**Reconciliationsof Changes in Reserves**

** **

Thefollowing table sets forth the reconciliation of our gross reserves as at December 31,2008, using forecast price and cost estimates derived from the GLJ Report.  Gross reserves as at December 31, 2008and as at December 31, 2007 include working interest reserves beforeroyalties payable and without including gross royalties receivable.

 

RECONCILIATIONOFGROSS RESERVESBY PRINCIPAL PRODUCT TYPEFORECAST****PRICES AND COSTS

 
| ** **             | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL**   | ** ** | **NATURAL GAS**               | ** ** |
|------------------------|------------|-----------------------------------------|------------|----------------------|------------|------------------------------------|------------|
| **FACTORS**            | ** ** | **Proved  (Mbbl)**                      | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Mbbl)** | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Bcf)** | ** ** | **Probable  (Bcf)** | ** ** | **Proved  Plus  Probable  (Bcf)** | ** ** |
|                   |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31, 2007 |       | 110,686                                 |       | 29,698               |       | 140,384                            |       | 2,353 |   | 781 |   | 3,134 |   | 589.8 |   | 165.1 |   | 754.9 |   |
|                   |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Discoveries            |       | 55                                      |       | 26                   |       | 81                                 |       | 0 |   | 0 |   | 0 |   | 4.3 |   | 1.9 |   | 6.3 |   |
| Extensions             |       | 860                                     |       | 477                  |       | 1,337                              |       | 15 |   | 5 |   | 20 |   | 50.5 |   | 52.3 |   | 102.8 |   |
| Infill Drilling        |       | 2,685                                   |       | 709                  |       | 3,394                              |       | 160 |   | (110 | ) | 50 |   | 141.2 |   | 37.4 |   | 178.6 |   |
| Improved Recovery      |       | 1,108                                   |       | 300                  |       | 1,408                              |       | 0 |   | 0 |   | 0 |   | 0.6 |   | 0.3 |   | 0.8 |   |
| Technical Revisions    |       | (1,095                                  | )          | (1,004               | )          | (2,099                             | )          | 137 |   | (68 | ) | 68 |   | 18.6 |   | 5.3 |   | 23.8 |   |
| Acquisitions           |       | 46                                      |       | 15                   |       | 61                                 |       | 7 |   | 2 |   | 9 |   | 0.0 |   | 0.1 |   | 0.1 |   |
| Dispositions           |       | 0                                       |       | 0                    |       | 0                                  |       | 0 |   | 0 |   | 0 |   | 0.0 |   | 0.0 |   | 0.0 |   |
| Economic Factors       |       | 496                                     |       | (83                  | )          | 413                                |       | 58 |   | 30 |   | 88 |   | 1.9 |   | 0.7 |   | 2.6 |   |
| Production             |       | (9,930                                  | )          | 0                    |       | (9,930                             | )          | (363 | ) | 0 |   | (363 | ) | (69.9 | ) | 0.0 |   | (69.9 | ) |
|                   |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31, 2008 |       | 104,912                                 |       | 30,138               |       | 135,049                            |       | 2,366 |   | 640 |   | 3,006 |   | 736.9 |   | 263.1 |   | 1,000.0 |   |

 
| ** **              | ** ** | **NATURAL GAS LIQUIDS** | ** ** | **TOTAL**            | ** ** |
|-------------------------|------------|-----------------------------------|------------|----------------------|------------|
| **FACTORS**             | ** ** | **Proved  (Mbbl)**                | ** ** | **Probable  (Mbbl)** | ** ** | **Proved Plus  Probable  (Mbbl)** | ** ** | **Proved  (mboe)** | ** ** | **Probable  (mboe)** | ** ** | **Proved Plus  Probable  (mboe)** | ** ** |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 11,249                            |       | 2,969                |       | 14,218 |   | 222,592 |   | 60,958 |   | 283,550 |   |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| Discoveries             |       | 17                                |       | 8                    |       | 25 |   | 794 |   | 355 |   | 1,149 |   |
| Extensions              |       | 199                               |       | 145                  |       | 344 |   | 9,486 |   | 9,348 |   | 18,834 |   |
| Infill  Drilling        |       | 758                               |       | 177                  |       | 935 |   | 27,132 |   | 7,012 |   | 34,144 |   |
| Improved  Recovery      |       | 60                                |       | 10                   |       | 70 |   | 1,264 |   | 355 |   | 1,619 |   |
| Technical  Revisions    |       | 141                               |       | 17                   |       | 158 |   | 2,279 |   | (178 | ) | 2,101 |   |
| Acquisitions            |       | 0                                 |       | 0                    |       | 0 |   | 54 |   | 37 |   | 91 |   |
| Dispositions            |       | 0                                 |       | 0                    |       | 0 |   | 0 |   | 0 |   | 0 |   |
| Economic  Factors       |       | 30                                |       | 4                    |       | 34 |   | 898 |   | 73 |   | 971 |   |
| Production              |       | (1,397                            | )          | 0                    |       | (1,397 | ) | (23,345 | ) | 0 |   | (23,345 | ) |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| December 31,  2008 |       | 11,057                            |       | 3,330                |       | 14,386 |   | 241,154 |   | 77,960 |   | 319,114 |   |

 

14

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**AdditionalInformation Relating to Reserves Data**

** **

***Proved and Probable Undeveloped Reserves***

*** ***

Undevelopedreserves are attributed by GLJ in accordance with standards and procedurescontained in the COGE Handbook.  Provedundeveloped reserves are those reserves that can be estimated with a highdegree of certainty and are expected to be recovered from known accumulationswhere a significant expenditure is required to render them capable ofproduction.  Probable undevelopedreserves are those reserves that are less certain to be recovered than provedreserves and are expected to be recovered from known accumulations where asignificant expenditure is required to render them capable of production.

 

Thefollowing table discloses by each product type the volumes of proved andprobable undeveloped reserves that were first attributed in each of the mostrecent three financial years and, in the aggregate, before that time.

 

**Proved Undeveloped Reserves**

 
| ** ** | ** ** | **Light & Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)** | ** ** | **Natural Gas  (MMcf)** | ** ** | **Natural Gas Liquids  (Mbbl)** | ** ** | **Oil Equivalent  (mboe)** | ** ** |
|------------|------------|---------------------------------------------------|------------|----------------------------|------------|------------------------------|------------|-------------------------------------------|------------|---------------------------------|------------|
| ** ** | ** ** | **First    Attributed**                           | ** ** | **Total  at   Year-end**   | ** ** | **First    Attributed**      | ** ** | **Total  at   Year-end**                  | ** ** | **First    Attributed**         | ** ** | **Total  at   Year-end** | ** ** | **First    Attributed** | ** ** | **Total  at   Year-end** | ** ** | **First    Attributed** | ** ** | **Total  at   Year-end** | ** ** |
| Prior      |       | 19,863                                            |       | 19,863                     |       | 40                           |       | 40                                        |       | 118,645                         |       | 118,645 |   | 1,346 |   | 1,346 |   | 41,023 |   | 41,023 |   |
| 2006       |       | 2,170                                             |       | 11,861                     |       | —                       |       | —                                    |       | 29,866                          |       | 121,976 |   | 434 |   | 1,827 |   | 7,584 |   | 34,017 |   |
| 2007       |       | 2,401                                             |       | 11,131                     |       | 11                           |       | 11                                        |       | 40,101                          |       | 122,061 |   | 235 |   | 1,484 |   | 9,331 |   | 32,970 |   |
| 2008       |       | 865                                               |       | 7,919                      |       | —                       |       | —                                    |       | 152,082                         |       | 268,684 |   | 683 |   | 2,000 |   | 26,895 |   | 54,700 |   |

 

**Probable Undeveloped Reserves**

 
| ** ** | ** ** | **Light & Medium Oil  (Mbbl)** | ** ** | **Heavy Oil  (Mbbl)** | ** ** | **Natural Gas  (MMcf)** | ** ** | **Natural Gas Liquids  (Mbbl)** | ** ** | **Oil Equivalent  (mboe)** | ** ** |
|------------|------------|---------------------------------------------------|------------|----------------------------|------------|------------------------------|------------|-------------------------------------------|------------|---------------------------------|------------|
| ** ** | ** ** | **First  Attributed**                             | ** ** | **Total  at  Year-end**    | ** ** | **First  Attributed**        | ** ** | **Total  at  Year-end**                   | ** ** | **First  Attributed**           | ** ** | **Total  at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total  at  Year-end** | ** ** | **First  Attributed** | ** ** | **Total  at  Year-end** | ** ** |
| Prior      |       | 10,291                                            |       | 10,291                     |       | 247                          |       | 247                                       |       | 58,887                          |       | 58,887 |   | 929 |   | 929 |   | 21,282 |   | 21,282 |   |
| 2006       |       | 3,698                                             |       | 10,331                     |       | —                       |       | 258                                       |       | 3,782                           |       | 56,020 |   | 300 |   | 1,002 |   | 4,628 |   | 20,928 |   |
| 2007       |       | 1,832                                             |       | 10,057                     |       | 113                          |       | 211                                       |       | 22,534                          |       | 67,837 |   | 178 |   | 1,034 |   | 5,879 |   | 22,608 |   |
| 2008       |       | 972                                               |       | 8,511                      |       | —                       |       | 93                                        |       | 79,623                          |       | 153,050 |   | 283 |   | 1,346 |   | 14,526 |   | 35,458 |   |

 

Over 75per cent of the proved plus probable undeveloped reserves are located in theDawson, Ante Creek, Weyburn and Dawson West Area properties.  In each case, we have planned a program forthe development of a portion of the undeveloped reserves in these areas in2009.  For further information, see “AdditionalInformation Relating to Reserve Data — Exploration and Development Activities”.

 

In somecases it will take us longer than two years to develop these reserves.  We plan to develop the majority of the provedundeveloped reserves in the reserves evaluation over the next four years andplan to develop the majority of the probable undeveloped reserves over the nextseven years.  The pace of development ofthese reserves is influenced by many factors, including the ongoing developmentof the infrastructure in the Montney assets, the outcomes of the yearlydrilling and reservoir evaluations, as well as capital constraints related tothe current economic conditions.

 

***Significant Factors or Uncertainties***

*** ***

We havea significant amount of proved undeveloped and probable reserves assigned tothe Dawson and the Dawson West Area gas fields in northeast BritishColumbia.  Sophisticated and expensivetechnology is required for these wells to produce.  At the current prices, these wells areeconomic; however, should gas prices fall materially, the wells may not beeconomic to drill.

 

Furtherdegradation in future commodity price forecasts relative to the forecast in theGLJ Report can also have a negative impact on the economics of the developmentof the undeveloped reserves, unless significant moderation in the future costsof development are not also realized.

 

15

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**Other Oil andGas Information**

** **

Our portfolio of properties as at December 31, 2008 includes bothunitized and non-unitized oil and natural gas production.  In general, the properties contain long life,low decline rate reserves and include interests in several major oil and gasfields.

 

***Principal Properties***

*** ***

The following is a description of our principal oil and natural gasproperties as at December 31, 2008. Reserves amounts are stated at December 31, 2008, based onescalated cost and price assumptions as evaluated in the GLJ Report prepared byGLJ (see “Statement of Reserves Data and Other Oil and Gas Information”).  Information in respect of gross and net acresand well counts are as at December 31, 2008, and information in respect ofproduction is for the year ended December 31, 2008 except where indicatedotherwise.  Due to the fact that we havebeen active at acquiring additional interests in our principal properties, theworking interest share and interest in gross and net acres and wells as at December 31,2008 may not directly correspond to the stated production for the year whichonly includes production since the date the interests were acquired by us.  The estimates of reserves and future netrevenue for individual properties may not reflect the same confidence level asestimates of reserves and future net revenue for all properties, due to theeffects of aggregation.

 

All of the properties described below are located in the WesternCanadian Sedimentary Basin and within the Canadian provinces of BritishColumbia, Alberta or Saskatchewan.  Theproperties represent 62 per centof the total gross proved plus probable reserves as assigned by GLJ in the GLJReport.  There are no other propertieswhich individually account for more than 2.9 per cent of the total gross provedplus probable reserves as assigned by GLJ in the GLJ Report.  The Dawson West Area property has gross provedreserves of 3,287 mboe and gross proved plus probable reserves of 7,550 mboereserves attributed which are capable of producing, but which are not yetproducing because of pipeline, processing and other infrastructure constraints.  There are no other material properties towhich reserves have been attributed which are capable of producing but whichare not producing and there are no material statutory or mandatoryrelinquishments, surrenders, back-ins or changes in ownership provisions.

 
| ** **                 | ** ** | **Gross Reserves and Gross Production** | ** ** |
|----------------------------|------------|-------------------------------------------------------------|------------|
| ** **                 | ** ** | **2008********Production**                                  | ** ** | **Proved  Reserves** | ** ** | **Proved plus Probable Reserves** | ** ** |
| ** **                 | ** ** | **(boe/d)**                                                 | ** ** | **(mboe)** | ** ** | **(mboe)** | ** ** | **(%)** | ** ** |
|                       |       |                                                        |       |   |   |   |   |   |   |
| Dawson                     |       | 7,222                                                       |       | 48,760 |   | 69,958 |   | 21.9 |   |
| Ante Creek                 |       | 5,084                                                       |       | 20,042 |   | 26,075 |   | 8.2 |   |
| Redwater                   |       | 3,998                                                       |       | 22,377 |   | 26,731 |   | 8.4 |   |
| Lougheed                   |       | 2,622                                                       |       | 5,941 |   | 7,902 |   | 2.5 |   |
| Jenner                     |       | 2,615                                                       |       | 10,067 |   | 12,809 |   | 4.0 |   |
| Pouce Coupe                |       | 2,549                                                       |       | 3,514 |   | 4,395 |   | 1.4 |   |
| Hatton                     |       | 2,117                                                       |       | 8,072 |   | 9,603 |   | 3.0 |   |
| North Pembina Cardium Unit |       | 1,831                                                       |       | 12,890 |   | 15,125 |   | 4.7 |   |
| Weyburn Unit               |       | 1,824                                                       |       | 10,197 |   | 15,805 |   | 5.0 |   |
| Berrymoor Cardium Unit     |       | 1,668                                                       |       | 8,384 |   | 10,640 |   | 3.3 |   |

 

***Dawson***

*** ***

TheDawson property is located in northeast British Columbia. We are the operatorand own an average land interest of 92 per cent in approximately 32,900 gross hectares(30,115 net hectares).  We operate alarge area compression facility where the natural gas and liquids are sent to athird party operated facility. During 2008, gross production from the areaaveraged 7,222 boe/d of natural gas and natural gas liquids from 85 net wellsprincipally from the upper Montney zone. During 2008, 27 new wells were drilled. GLJ assigned gross provedreserves of 48,760 mboe and gross proved plus probable reserves of 69,958 mboeof natural gas and natural gas liquids to this area, or 21.9 per cent of totalgross proved plus probable reserves.  GLJhas estimated as at October 1, 2008, that the Dawson property contained3.5 Tcf of natural gas classified as Discovered Petroleum Initially In Place (“**DPIIP**”) of which 2.0 Tcf of natural gasclassified as DPIIP are on sections to which reserves have been assigned by GLJin the GLJ Report.  The GLJ best estimateof DPIIP uses a three per cent porosity cut-off and an average drillingassumption of three horizontal equivalent wells per section.  Further development drilling and testing isrequired to determine the

 

16

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scaleof contingent resources.  The proven andprobable reserves assigned by GLJ to the Dawson property as at December 31,2008 in the GLJ Report represents a 25 per cent recovery factor.

 

Inaddition to the Dawson property, we own an average land interest of 76 per centin approximately 24,938 gross hectares (18,988 net hectares) in the Dawson West Area which we believe is prospectivein the upper Montney zone.  GLJ hasestimated as at October 1, 2008 that the Dawson West Area contains 4.6 Tcfof natural gas classified as DPIIP in the upper Montney zone.  This GLJ best estimate is based on a threeper cent porosity cut-off and limited development drilling and testingdata.  Given the current stage ofdevelopment, this best estimate will be subject to potentially significantchanges with further development activity. Further development drilling and testing is required to determine thescale of contingent resources.  TheDawson West Area has been assigned gross proved reserves of 3,287 boe and grossproved plus probable reserves of 7,550 mboe in the GLJ Report which is capableof producing but which are not yet producing because of pipeline, processingand other infrastructure constraints.  Wecurrently plan to construct a 60 MMcfpd gas plant for production in the Dawsonand Dawson West Area.

 

**The resources estimates of natural gas are estimates only andthe actual resources may be greater than or less than the estimates providedherein.  A capital development projectfor the recovery of this volume of DPIIP cannot be defined at this time.  There is no certainty that it will beeconomically viable or technically feasible to produce any portion of thisnatural gas classified as DPIIP.**

 

***Ante Creek***

*** ***

TheAnte Creek property is located in northwest Alberta. We are the operator andown an average land interest of 93 per cent. Oil production is processedthrough three operated facilities, while the gas is processed through oneoperated facility and one third party facility. During 2008, gross productionfrom the area averaged 5,084 boe/d of oil, natural gas and natural gas liquidsfrom 169 net wells. During 2008, 12 new wells were drilled. GLJ assigned grossproved reserves of 20,042 mboe and gross proved plus probable reserves of26,075 mboe of oil, natural gas and natural gas liquids to this area, or 8.2per cent of total gross proved plus probable reserves.

 

***Redwater***

*** ***

TheRedwater property is located in central Alberta. We are the operator and own anaverage land interest of 86 per cent. Oil and solution gas are both processedat an operated central facility. During 2008, gross production from the areaaveraged 3,998 boe/d of oil, natural gas and natural gas liquids from 404 netwells. During 2008, eight new wells were drilled. GLJ assigned gross provedreserves of 22,377 mboe and gross proved plus probable reserves of 26,731 mboeof oil, natural gas and natural gas liquids to this area, or 8.4 per cent oftotal gross proved plus probable reserves.

 

ARCbelieves that the Redwater field is a prime candidate for Enhanced Oil Recovery(“EOR”) through the use of Carbon Dioxide (“CO2”)injection.  Redwater is one of thelargest conventional oil pools in Canada and has been producing for over 50years.  While production to date on ourproperties is approximately 600 million barrels of oil, we believe that thereare substantial quantities of oil remaining in the reservoir which areunrecoverable with conventional technology. During 2008, ARC commenced the injection of CO2 at a pilotEOR project in Redwater.  The pilot isdesigned to confirm whether the Redwater reef is amenable to CO2 flooding and that incremental oil can be mobilized and recovered.  Definitive results from this CO2 pilot project are notexpected for at least another 12 months. Large amounts of CO2 need to be acquired on economic terms for alarge scale project like the Redwater EOR to proceed.  Currently, there are no large scale CO2 capture facilities orinfrastructure to transport CO2 in Alberta. Large infrastructure investments are required to capture, transport andinject CO2 and long term agreements willneed to be negotiated with emitters for the CO2 supply. For these types of projects to be possible, higher commodity prices willneed to prevail and most importantly, governments will need to clearlyestablish long term regulations surrounding the capture of CO2 emissions.   There is no assurance that this project willproceed or be economically viable.

*** ***

***Lougheed***

*** ***

TheLougheed property is located in southeast Saskatchewan. We are the operator andown an average land interest of 80 per cent. Production is handled by anoperated battery and gas plant. During 2008, gross production from the

 

17

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areaaveraged 2,622 boe/d of oil and natural gas liquids from 122 net wells. During2008, four new wells were drilled. GLJ assigned gross proved reserves of 5,941mboe and gross proved plus probable reserves of 7,902 mboe of oil and naturalgas liquids to this area, or 2.5 per cent of total gross proved plus probablereserves.

 

***Jenner***

*** ***

TheJenner property is located in southeast Alberta. We own a combination ofoperated and non-operated acreage with an average land interest of 88 per cent.We operate four gas compression and dehydration facilities in the area. During2008, gross production from the area averaged 2,615 boe/d of natural gas from836 net wells. During 2008, no new wells were drilled. GLJ assigned grossproved reserves of 10,067 mboe and gross proved plus probable reserves of12,809 mboe of natural gas to this area, or four per cent of total gross provedplus probable reserves.

 

***Pouce Coupe***

*** ***

ThePouce Coupe property is located in northwest Alberta. We are the operator andown an average land interest of 74 per cent. The sweet gas is processed throughan operated gas plant and the sour gas flows to a third party processing plant.During 2008, gross production from the area averaged 2,549 boe/d of oil,natural gas and natural gas liquids from 37 net wells. During 2008, two wellswere drilled. GLJ assigned gross proved reserves of 3,514 mboe and gross provedplus probable reserves of 4,395 mboe of oil, natural gas and natural gas liquidsto this area, or 1.4 per cent of total gross proved plus probable reserves.

 

***Hatton***

*** ***

TheHatton property is located in southwest Saskatchewan. We own a combination ofoperated and non-operated acreage with an average land interest of 44 per cent.The operated production flows through three operated compression anddehydration facilities where our working interest ranges from 50 to 100 percent. During 2008, gross production from the area averaged 2,117 boe/d ofnatural gas from 434 net wells. During 2008, 23 new wells were drilled. GLJassigned gross proved reserves of 8,072 mboe and gross proved plus probablereserves of 9,603 mboe of natural gas to this area, or three per cent of totalgross proved plus probable reserves.

*** ***

***North Pembina Cardium Unit***

*** ***

TheNorth Pembina Cardium Unit No. 1 is located in central Alberta. We are theoperator and own a 45.57 per cent interest in the unit. Production is processedthrough two operated oil treatment facilities and one operated solution gasplant. During 2008, gross production from the unit averaged 1,831 boe/d of oil,natural gas and natural gas liquids from 177 net wells. During 2008, ten newwells were drilled. GLJ assigned gross proved reserves of 12,890 mboe and grossproved plus probable reserves of 15,125 mboe of oil, natural gas and naturalgas liquids to this unit, or 4.7 per cent of total gross proved plus probablereserves.

 

***Weyburn Unit***

*** ***

TheWeyburn unit is located in southeast Saskatchewan. EnCana Corporation operatesthe unit and we have a working interest of 6.95 per cent. The unit is currentlyundergoing a CO2 flood for enhanced oil recovery. During 2008gross production from the unit averaged 1,824 boe/d of oil from 58 net wells.During 2008, 34 new wells were drilled. GLJ assigned gross proved reserves of10,197 mboe and gross proved plus probable reserves of 15,805 mboe of oil andnatural gas liquids to this unit, or five per cent of total gross proved plusprobable reserves.

 

***Berrymoor Cardium Unit***

*** ***

TheBerrymoor Cardium Unit is located in central Alberta. We are the operator andown a 73.25 per cent interest in the unit. Oil is processed at an operatedbattery while the solution gas flows to a third party facility.  During 2008, gross production from the unit averaged1,668 boe/d of oil, natural gas and natural gas liquids from 89 net wells.During 2008, seven new wells were drilled. GLJ assigned gross proved reservesof 8,384 mboe and gross proved plus probable reserves of 10,640 mboe of oil,natural gas and natural gas liquids to this unit, or 3.3 per cent of totalgross proved plus probable reserves.

 

18

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***Oil And Gas Wells***

*** ***

Thefollowing table sets forth the number and status of wells in which we had aworking interest as at December 31, 2008.

 
| ** **        | ** ** | **Oil Wells** | ** ** | **Natural Gas Wells** | ** ** |
|-------------------|------------|--------------------|------------|---------------------------------|------------|
| ** **        | ** ** | **Producing**      | ** ** | **Non-Producing**               | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** |
| ** **        | ** ** | **Gross**          | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|              |       |               |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Alberta           |       | 4,066              |       | 1,604                           |       | 1,109 |   | 138 |   | 4,387 |   | 1,908 |   | 199 |   | 38 |   |
| British  Columbia |       | 7                  |       | 1                               |       | 1 |   | — |   | 256 |   | 91 |   | 38 |   | 16 |   |
| Saskatchewan      |       | 2,141              |       | 802                             |       | 286 |   | 89 |   | 5,498 |   | 868 |   | 54 |   | 20 |   |
| Manitoba          |       | 561                |       | 125                             |       | 20 |   | 2 |   | — |   | — |   | — |   | — |   |
| Total             |       | 6,775              |       | 2,532                           |       | 1,416 |   | 229 |   | 10,141 |   | 2,867 |   | 291 |   | 74 |   |

*** ***

***Properties with no Attributable Reserves***

*** ***

Thefollowing table sets out our undeveloped land holdings as at December 31,2008.

 
| ** **        | ** ** | **Undeveloped Hectares** | ** ** |
|-------------------|------------|-------------------------------|------------|
| ** **        | ** ** | **Gross**                     | ** ** | **Net** | ** ** |
|              |       |                          |       |   |   |
| Alberta           |       | 227,460                       |       | 101,215 |   |
| British  Columbia |       | 85,192                        |       | 60,382 |   |
| Manitoba          |       | 674                           |       | 433 |   |
| Saskatchewan      |       | 95,579                        |       | 59,670 |   |
| Total             |       | 408,905                       |       | 221,700 |   |

 

InBritish Columbia, we have 55**,**800 gross hectares and 49,000 net hectares in Dawson and theDawson West Area which have varying degrees of prospectively in the Montneyzones.  For more information, see “AdditionalInformation Relating to Reserve Data — Principal Properties — Dawson and DawsonWest Area”.

 

Wecurrently have no material work commitments on these lands.  Approximately 38,000 net hectares of our undeveloped land holdings are slated toexpire by December 31, 2009, however we anticipate that a portion of theundeveloped lands will be continued. There are no material expiries in our core holdings.

 

***Forward Contracts***

*** ***

We are exposed to market risks resulting from fluctuations in commodityprices, foreign exchange rates and interest rates in the normal course ofoperations.  A variety of derivativeinstruments are used to reduce our exposure to fluctuations in commodityprices, foreign exchange rates and interest rates.  We may also potentially be exposed to lossesin the event of default by the counterparties to these derivativeinstruments.  We manage this risk bydiversifying our derivative portfolio among a number of financially soundcounterparties.

 

In general, without specific approval of theBoard of Directors which is granted from time to time, management of ARCResources is permitted to hedge up to a maximum of 50 per cent of forecastedproduction on a boe basis for up to six months, 35 per cent for up to ninemonths, 25 per cent for up to 15 months, and 15 per cent for up to 18 months.

 

We have a Risk Committee of the Board ofDirectors that reviews financial and business risks including activitiesrelated to our hedging program.  Ourmanagement executes financial hedging transactions to reduce the Trust’sexposure to market price fluctuations either by price protection, throughderivatives or swaps, or diversifying its price exposure in accordance with theBoard of Directors guidelines or approval on specific transactions.

 

A summary of financial and physical contracts in respect of hedgingactivities can be found in Note 13 “Market Risk Management” to our auditedconsolidated financial statements for the year ended December 31, 2008 andin the section under the heading “Risk Management and Hedging Activities” inour Management Discussion and Analysis

 

19

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and results of operations for the year ended December 31, 2008which have been filed on SEDAR at www.sedar.com, and both of which note andsection are incorporated in this Annual Information Form by reference.

 

***Additional Information Concerning Abandonment and Reclamation Costs***

*** ***

Thefollowing table sets forth information respecting future abandonment andreclamation costs for surface leases, wells, facilities and pipelines which weexpect to incur for the periods indicated.

 
| ** **                          | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Undiscounted** | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Discounted at 10%** | ** ** |
|-------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------|------------|
| ** **                          | ** ** | **($MM)**                                                                                       | ** ** | **($MM)**                                                                                                      | ** ** |
| Total as at  December 31, 2008 |       | 1,316.6                                                                                         |       | 71.9                                                                                                           |       |
| Anticipated  to be paid in 2009     |       | 4.9                                                                                             |       | 4.4                                                                                                            |       |
| Anticipated  to be paid in 2010     |       | 5.0                                                                                             |       | 4.2                                                                                                            |       |
| Anticipated  to be paid in 2011     |       | 5.5                                                                                             |       | 4.1                                                                                                            |       |

 

We willbe liable for our share of ongoing environmental obligations and for theultimate reclamation of the properties held by us upon abandonment.  We estimate that we have an interest in 6,620net wells that will require abandonment and reclamation over the next 51 yearswith the majority of payments being made in years 2049 to 2059.  These ongoing environmental obligations areexpected to be funded out of cash flow from operating activities and anybalance available in our reclamation fund.

 

We havea reclamation fund to pay future asset retirement obligations costs.  We currently estimate that the futureenvironmental and reclamation obligations in respect of our properties will beapproximately $1,317 million calculated by escalating costs at two per cent peryear (reflected in our audited consolidated financial statements as an assetretirement obligation of $141.5 million calculated by escalating costs at twoper cent per year and discounting at a blended rate of 6.6 per cent).  For more information, see Note 11 of ouraudited consolidated financial statements and the section in our Management’sDiscussion and Analysis of operations of such financial statements under theheading “Asset Retirement Obligation and Reclamation Fund”, which note andsection are incorporated in this Annual Information Form by reference andare found on SEDAR at www.sedar.com.  TheBoard of Directors of ARC Resources has approved voluntary contributions to ourreclamation fund over a twenty year period that results in minimum annualcontributions of $6 million ($6million in 2008) based on properties owned as at December 31, 2008.  During 2008, $9.7 million ($17.5 million for2007) of actual expenditures were charged against the reclamation fundresulting in a net reduction of our reclamation fund for the year of $3.2million ($10.4 million net addition in 2007). The balance of this fund as of December 31, 2008 is $11.2 million.

 

Inaddition we have committed to a restricted reclamation trust associated withthe acquisition of the Redwater property pursuant to which ARC Resources hasagreed with the vendor of the Redwater property to contribute to such trustcertain minimum amounts, totalling approximately $110 million over a 50 yearperiod, to fund future environmental and reclamation obligations in respect ofthe Redwater properties, or to expend certain minimum amounts towardsdischarging these obligations. The restricted contribution commenced in 2006for $6.1 million and continues at a declining rate through 2055. The currentbalance of this trust as of December 31, 2008 is $17 million.

 

Weestimate the costs to abandon and reclaim all our shut in and producing wells,pipelines and facilities.  No estimate ofsalvage value is netted against the estimated cost.  Our model for estimating the amount andtiming of future abandonment and reclamation expenditures was created on anoperating area level.  Estimatedexpenditures for each operating area are based on the Energy ResourcesConservation Board methodology which details the cost of abandonment andreclamation in eight specific geographic regions.  Each region was assigned an average cost perwell to abandon and reclaim the wells in that area.

 

Abandonmentand reclamation costs have been estimated over a 50 year period.  Facility abandonment and reclamation costsare scheduled to be incurred in the year following the end of the reserves lifeof its associated reserve.

 

Theadditional liability associated with well, pipelines and facilities reclamationcosts which were not deducted by GLJ in estimating future net revenue in theGLJ Report are $1,071.6 million (escalating costs at two per cent and

 

20

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undiscounted)and $18.9 million (escalating costs at two per cent and discounted at 10 percent).  Only the abandonment costsassociated with wells with reserves were deducted by GLJ in estimating futurenet revenue.

 

***Tax Horizon***

*** ***

As aresult of our tax efficient structure, annual taxable income is currentlytransferred from ARC Resources to the Trust and from the Trust toUnitholders.  This is primarilyaccomplished through the deduction by ARC Resources of the Royalties onunderlying oil and gas properties and the deduction of interest on the LongTerm Notes.

 

Theeffect of the SIFT Rules is reflected in the after tax net revenue amountsdisclosed in the Reserves Data (Forecast Prices and Costs) in this AnnualInformation Form, but uses a provincial rate of 13 per cent rather than 10 percent as currently anticipated.  See “OurBusiness — Federal Tax Changes for Income Trusts and Corporations”.

 

Untilthe SIFT tax becomes applicable to the Trust, it is expected that minimalincome taxes will be incurred by the Trust or its operating entities ascurrently structured.  However, annualoperating income retained to pay a portion of capital expenditures or used torepay debt may result in income tax liabilities within ARC Resources from timeto time.  In addition, any furtherdeclines in oil and natural gas prices and consequential reduced revenues mayresult in reduced distributions to Unitholders and income tax incurred by ARCResources.  See “Risk Factors — FederalTax Changes for Income Trusts and Corporations” and “Risk Factors — Changes inLegislation”.

 

***Capital Expenditures***

*** ***

Thefollowing tables summarize capital expenditures (net of incentives and net ofcertain proceeds and including capitalized general and administrative expenses)related to our activities for the year ended December 31, 2008:

 
| ** **                     | ** ** | **2008  $MM** | ** ** |
|--------------------------------|------------|---------------|------------|
| Property  acquisition costs(1) |       |          |       |
| Proved  properties             |       | 6.3           |       |
| Undeveloped  properties        |       | 44.7          |       |
| Exploration  costs(2)          |       | 164.1         |       |
| Development  costs(3)          |       | 371.1         |       |
| Corporate  capital costs       |       | 13.4          |       |
| Total                          |       | 599.6         |       |

 

----

Notes:

(1)           Represents acquisition costs net ofdispositions and property swaps.

(2)           Includes costs of land acquired ($119.6million), geological and geophysical capital expenditures and drilling costsfor 2008 exploration wells drilled.

(3)           Includes costs of land acquired ($2.8million), development and facilities capital expenditures and drilling costsfor 2008 development wells drilled.

 

***Exploration and Development Activities***

*** ***

Thefollowing table sets forth the gross and net exploratory and development wellsthat we participated in during the year ended December 31, 2008:

 
| ** **            | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** | **Total** | ** ** |
|-----------------------|------------|----------------------------|------------|----------------------------|------------|-----------|------------|
| ** **            | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Light and  Medium Oil |       | 13                         |       | 12                         |       | 205       |       | 103 |   | 218 |   | 115 |   |
| Heavy Oil             |       | —                     |       | —                     |       | 16        |       | — |   | 16 |   | — |   |
| Natural Gas           |       | 25                         |       | 11                         |       | 210       |       | 87 |   | 235 |   | 98 |   |
| Service               |       | —                     |       | —                     |       | 26        |       | 7 |   | 26 |   | 7 |   |
| Dry                   |       | 2                          |       | 2                          |       | 7         |       | 1 |   | 9 |   | 3 |   |
| Total:                |       | 40                         |       | 25                         |       | 464       |       | 198 |   | 504 |   | 223 |   |

 

For 2009, the Trust has planned an extensive capital program of $450million.  The program comprises costs todevelop the core assets of the Trust as well as construction costs for a new 60mmcf per day gas plant for production in the Dawson and Dawson West Area.  Our capital program is subject to variationthroughout the year depending

 

21

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upon prices for oil and natural gas and there is no assurance that allor any part of our capital program will be expended as planned.  In addition, capital expenditures may be madeon the acquisition of undeveloped land or oil and natural gas reserves.  See “Risk Factors — Volatility of Oil andNatural Gas Prices, “Risk Factors — Global Financial Crisis” and “Risk Factors —Capital Markets”.

 

See “Risk Factors — Operational Matters” and “Risk Factors — ProjectRisks”.

 

***Production Estimates***

 

Thefollowing table sets out the volume of our production estimated for the yearended December 31, 2009 which is reflected in the estimate of gross provedreserves and gross probable reserves disclosed in the tables contained under “Statementof Reserves Data and Other Oil and Gas Information - Disclosure ofReserves Data”.

 
| ** **                  | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Total**   | ** ** |
|-----------------------------|------------|--------------------------------|------------|--------------------|------------|----------------------|------------|-------------------------------|------------|-------------|------------|
| ** **                  | ** ** | **(bbl/d)**                    | ** ** | **(bbl/d)**        | ** ** | **(Mcfpd)**          | ** ** | **(bbl/d)**                   | ** ** | **(boe/d)** | ** ** |
| ** **                  | ** ** | **Gross**                      | ** ** | **Net**            | ** ** | **Gross**            | ** ** | **Net**                       | ** ** | **Gross**   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Total Proved                |       | 25,640                         |       | 21,766             |       | 903                  |       | 949                           |       | 185,889     |       | 151,284 |   | 3,529 |   | 2,474 |   | 61,054 |   | 50,403 |   |
| Total Proved  Plus Probable |       | 26,896                         |       | 22,723             |       | 941                  |       | 983                           |       | 191,261     |       | 155,180 |   | 3,639 |   | 2,552 |   | 63,353 |   | 52,122 |   |

 

***Production History***

 

The following tables summarize certain information inrespect of our production, product prices received, royalties paid, operatingexpenses and resulting netback for the periods indicated below:

 
| ** **                              | ** ** | **Quarter Ended** | ** ** | ** **          | ** ** |
|-----------------------------------------|------------|------------------------|------------|---------------------|------------|
| ** **                              | ** ** | **2008**               | ** ** | **Year Ended** | ** ** |
| **(6:1)**                               | ** ** | **Mar. 31**       | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2008** | ** ** |
| Average  Daily Production(1)            |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil (bbl/d)     |       | 27,718                 |       | 26,288              |       | 27,211 |   | 27,737 |   | 27,239 |   |
| Heavy Oil  (bbl/d)                      |       | 1,346                  |       | 1,253               |       | 1,298 |   | 1,198 |   | 1,274 |   |
| Gas (MMcfpd)                            |       | 204.3                  |       | 194.7               |       | 192.0 |   | 195.1 |   | 196.5 |   |
| NGLs (bbl/d)                            |       | 3,856                  |       | 3,906               |       | 3,822 |   | 3,858 |   | 3,861 |   |
| Combined  (boe/d)                       |       | 66,975                 |       | 63,896              |       | 64,325 |   | 65,313 |   | 65,126 |   |
|                                    |       |                   |       |                |       |   |   |   |   |   |   |
| Average Net  Production Prices Received |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 90.95                  |       | 119.03              |       | 114.92 |   | 56.81 |   | 94.97 |   |
| Heavy Oil  ($/bbl)                      |       | 64.43                  |       | 103.38              |       | 98.97 |   | 43.47 |   | 77.85 |   |
| Gas ($/Mcf)                             |       | 7.80                   |       | 10.41               |       | 8.68 |   | 7.48 |   | 8.58 |   |
| NGLs ($/bbl)                            |       | 68.54                  |       | 82.29               |       | 82.87 |   | 45.22 |   | 69.71 |   |
| Combined  ($/boe)                       |       | 66.94                  |       | 88.04               |       | 82.06 |   | 50.06 |   | 71.59 |   |
|                                    |       |                   |       |                |       |   |   |   |   |   |   |
| Royalties  Paid                         |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 14.20                  |       | 18.51               |       | 17.57 |   | 8.46 |   | 14.58 |   |
| Heavy Oil  ($/bbl)                      |       | 6.71                   |       | 11.38               |       | 10.53 |   | 4.95 |   | 8.41 |   |
| Gas ($/Mcf)                             |       | 1.54                   |       | 2.15                |       | 1.99 |   | 1.59 |   | 1.82 |   |
| NGLs ($/bbl)                            |       | 19.64                  |       | 22.96               |       | 23.83 |   | 11.91 |   | 19.58 |   |
| Combined  ($/boe)                       |       | 11.85                  |       | 15.79               |       | 15.00 |   | 9.14 |   | 12.91 |   |
|                                    |       |                   |       |                |       |   |   |   |   |   |   |
| Operating  Expenses (2)(3)              |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)     |       | 11.35                  |       | 15.50               |       | 13.80 |   | 13.63 |   | 13.91 |   |
| Heavy Oil  ($/bbl)                      |       | 10.90                  |       | 10.63               |       | 11.26 |   | 13.82 |   | 11.63 |   |
| Gas ($/Mcf)                             |       | 1.37                   |       | 1.18                |       | 1.19 |   | 1.18 |   | 1.19 |   |
| NGLs ($/bbl)                            |       | 8.11                   |       | 8.40                |       | 9.78 |   | 8.84 |   | 8.22 |   |
| Combined  ($/boe)                       |       | 9.55                   |       | 10.71               |       | 10.19 |   | 10.09 |   | 10.13 |   |

 

22

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| ** **                                               | ** ** | **Quarter Ended** | ** ** | ** **          | ** ** |
|----------------------------------------------------------|------------|------------------------|------------|---------------------|------------|
| ** **                                               | ** ** | **2008**               | ** ** | **Year Ended** | ** ** |
| **(6:1)**                                                | ** ** | **Mar. 31**       | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2008** | ** ** |
| Transportation  Paid                                     |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 0.03                   |       | 0.19                |       | 0.18 |   | 0.17 |   | 0.14 |   |
| Heavy Oil  ($/bbl)                                       |       | 1.31                   |       | 1.06                |       | 1.10 |   | 1.19 |   | 1.17 |   |
| Gas ($/Mcf)                                              |       | 0.22                   |       | 0.23                |       | 0.24 |   | 0.26 |   | 0.24 |   |
| NGLs ($/bbl)                                             |       | —                 |       | —              |       | — |   | — |   | — |   |
| Combined  ($/boe)                                        |       | 0.73                   |       | 0.79                |       | 0.80 |   | 0.86 |   | 0.80 |   |
|                                                     |       |                   |       |                |       |   |   |   |   |   |   |
| (Gain)/Loss  on Commodity and Foreign Exchange Contracts |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 6.50                   |       | 14.36               |       | 10.81 |   | (3.05 | ) | 7.03 |   |
| Heavy Oil  ($/bbl)                                       |       | —                 |       | —              |       | — |   | — |   | — |   |
| Gas ($/Mcf)                                              |       | (0.02                  | )          | 0.60                |       | 0.43 |   | (0.36 | ) | 0.16 |   |
| NGLs ($/bbl)                                             |       | —                 |       | —              |       | — |   | — |   | — |   |
| Combined  ($/boe)                                        |       | 2.63                   |       | 7.67                |       | 5.79 |   | (5.46 | ) | 3.17 |   |
|                                                     |       |                   |       |                |       |   |   |   |   |   |   |
| Netback Received(4)                                      |       |                   |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 58.87                  |       | 70.47               |       | 72.56 |   | 37.60 |   | 59.31 |   |
| Heavy Oil  ($/bbl)                                       |       | 45.51                  |       | 80.31               |       | 76.08 |   | 23.51 |   | 56.64 |   |
| Gas ($/Mcf)                                              |       | 4.69                   |       | 6.25                |       | 4.83 |   | 4.81 |   | 5.17 |   |
| NGLs ($/bbl)                                             |       | 40.79                  |       | 50.93               |       | 49.26 |   | 24.47 |   | 41.91 |   |
| Combined  ($/boe)                                        |       | 42.18                  |       | 53.08               |       | 50.28 |   | 35.43 |   | 44.58 |   |

 

----

Notes:

(1)           Before deduction of royalties.

(2)           Operating expenses are composed of directcosts incurred to operate both oil and gas wells.  A number of assumptions have been made in allocatingthese costs between oil, natural gas and natural gas liquids production.

(3)           Operating recoveries associated withoperated properties were excluded from operating costs and accounted for as areduction to general and administrative costs.

(4)           Netbacks are calculated by subtractingroyalties, operating costs, transportation costs, and losses/gains on commodityand foreign exchange contracts from revenues.

 

Noproperty accounts for more than 11.1 per cent of the production disclosedabove.  For more information, see “OtherOil and Gas Information — Principal Properties”.

** **

**MarketingArrangements**

** **

***Natural Gas***

*** ***

During2008, we continued our marketing strategy of maintaining a high level of directcontrol and diversification of marketing and transportation arrangements forour natural gas production.

 

Theaverage natural gas price we received during 2008 was $8.58 per Mcf as comparedto $6.75 per Mcf for 2007.  This pricewas achieved with a portfolio mix that on average through the year receivedAECO index based pricing for 68 per cent, aggregator netback prices for 20 percent, and Chicago Index Pricing for 12 per cent of total production.

 

Tomanage natural gas price volatility and to stabilize the revenue stream, ournatural gas portfolio is directed towards maintaining balanced exposure to U.S.and Canadian markets with market sensitive and hedgeable pricing terms, as wellas aggregator netback arrangements.  Dueto the winding up of two aggregator pools effective December 31, 2008, ARC’sfuture aggregator contract obligations have reduced to 13 per cent of total gassales.  We also strive for a highutilization of contracted pipeline and processing capacity.

 

***Crude Oil and Natural Gas Liquids***

*** ***

Ourliquids production in 2008 was comprised of approximately 51 per cent lightquality crude oil (greater than 35°API), 33 per cent medium quality crude oil(25 to 35 API), four per cent heavy quality crude (less than 25°API), four percent condensate and eight per cent natural gas liquids.  During 2008, our average sales prices were$94.97

 

23

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per bblfor light and medium crude oil, $77.85 per bbl for heavy crude oil and $69.71per bbl for natural gas liquids; these prices compare to 2007 prices of $70.77per bbl for light and medium crude oil, $50.55 per bbl for heavy crude oil and$54.79 per bbl for natural gas liquids. Our crude oil is sold under contracts of varying terms of up to oneyear, based on market sensitive pricing terms. Natural gas liquids are sold under annual arrangements.  Industry pricing benchmarks for crude oil andnatural gas liquids are continuously monitored to ensure optimal netbacks.

 

**SHARE CAPITAL OF ARCRESOURCES**

** **

**Common Shares**

** **

ARCResources has authorized for issuance an unlimited number of common shares ofwhich 1,000,121 common shares are issued and outstanding and held by theTrust.  The voting of such shares isdelegated to ARC Resources under the Trust Indenture.  The holders of common shares are entitled tonotice of, to attend and to one vote per share held at any meeting of theshareholders of ARC Resources; to receive dividends as and when declared by theBoard of Directors of ARC Resources on the common shares as a class, andsubject to prior satisfaction of all preferential rights to dividends attachedto all shares of other classes; and in the event of any liquidation,dissolution or winding-up of ARC Resources, whether voluntary or involuntary,or any other distribution of the assets of ARC Resources among its shareholdersfor the purpose of winding-up its affairs, and subject to prior satisfaction ofall preferential rights to return of capital on dissolution attached to allshares of other classes of shares of ARC Resources ranking in priority to thecommon shares in respect of return of capital on dissolution, to sharerateably, together with the shares of any other class of shares of ARCResources ranking equally with the common shares in respect of return ofcapital on dissolution, in such assets of ARC Resources as are available fordistribution.

 

**ExchangeableShares**

** **

ARCResources is authorized to issue an unlimited number of Exchangeable Shares ofwhich, as at December 31, 2008, 1,091,414 were outstanding.  The Exchangeable Shares rank prior to thecommon shares of ARC Resources, the second preferred shares of ARC Resourcesand any other shares ranking junior to the Exchangeable Shares with respect tothe payment of dividends and the distribution of assets in the event of theliquidation, dissolution or winding-up of ARC Resources; provided thatnotwithstanding such ranking ARC Resources shall not be restricted in any wayfrom repaying indebtedness of ARC Resources to the Trust from time totime.  The Exchangeable Share provisionshave been filed on SEDAR at www.sedar.com.

 

TheExchangeable Shares provide holders with a security having economic, ownershipand voting rights which are substantially equivalent to those of TrustUnits.  As at December 31, 2008 theExchange Ratio was 2.51668 Trust Units per Exchangeable Share.  Holders of Exchangeable Shares will notreceive distributions, rather the Exchangeable Shares are maintainedeconomically equivalent to the Trust Units by the progressive increase in theExchange Ratio to reflect distributions paid by the Trust to Unitholders.  The Exchangeable Shares are providedequivalent voting rights as those of Unitholders through an agreement (theExchangeable Share Voting and Exchange Trust Agreement) pursuant to which theholders of Exchangeable Shares can direct the Trustee to vote at meetings ofUnitholders.  The holders of ExchangeableShares are further assured of the delivery of Trust Units by us in satisfactionof the obligations of ARC Resources under the Exchangeable Share terms through theprovisions of another agreement (the Exchangeable Share SupportAgreement).  Copies of the ExchangeableShare Voting and Exchange Trust Agreement and the Exchangeable Share SupportAgreement have been filed on SEDAR at www.sedar.com.

 

ComputershareTrust Company of Canada acts as the transfer agent for the Exchangeable Shares.

 

Holdersof Exchangeable Shares are entitled to receive, as and when declared by theBoard of Directors in its sole discretion, from time to time, cumulativepreferential cash dividends in an amount per share equal to the Exchange Ratioon the preceding business day multiplied by the fair market value of a TrustUnit as at the preceding business day (determined on the basis of the weightedaverage price of the Trust Unit on the TSX for the 10 trading days precedingthat date).  It is not anticipated thatdividends will be declared or paid on the Exchangeable Shares, however theBoard of Directors has the right in its sole discretion to do so, and if so,the Exchange Ratio would be reduced accordingly to reflect such dividends.

 

ARCResources will not, without obtaining the approval of the holders of theExchangeable Shares:

 

24

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(a)           payany dividend on the common shares of ARC Resources, second preferred shares ofARC Resources or any other shares ranking junior to the Exchangeable Shares,other than the stock dividends payable in common shares of ARC Resources or anysuch other shares ranking junior to the Exchangeable Shares;

 

(b)           redeem,purchase or make any capital distribution in respect of the common shares ofARC Resources, second preferred shares of ARC Resources or any other sharesranking junior to the Exchangeable Shares;

 

(c)           redeemor purchase any other shares of ARC Resources ranking equally with respect tothe payment of dividends or on any liquidation distribution; or

 

(d)           issueany shares, other than Exchangeable Shares, second preferred shares of ARCResources or common shares of ARC Resources, which rank superior to theExchangeable Shares with respect to the payment of dividends or on anyliquidation distribution.

 

Notwithstandingthe foregoing, the restrictions in paragraphs (a), (b) and (c) aboveshall only be applicable if dividends which have been declared on theoutstanding Exchangeable Shares have not been paid in full.

 

TheExchangeable Share Provisions entitle the holder to exchange each ExchangeableShare at any time into the number of Trust Units equal to the Exchange Ratiothen in effect.  The Exchange Ratio isdetermined by reference to the distributions paid on Trust Units in a givenmonth and the current market price of the Trust Units.

 

**SecondPreferred Shares**

** **

ARCResources also has authorized an unlimited number of Second Preferred Shareswhich may at any time or from time to time be issued in one or moreseries.  Before any shares of aparticular series are issued, the Board of Directors of ARC Resources shall, byresolution, fix the number of shares that will form such series and shall,subject to the limitations set out herein, by resolution fix the designation,rights, privileges, restrictions and conditions to be attached to the SecondPreferred Shares of such series.  TheSecond Preferred Shares of each series shall rank behind the ExchangeableShares and on parity with the Second Preferred Shares of every other serieswith respect to accumulated dividends and return of capital.  The Second Preferred Shares are entitled to apreference over the Common Shares and over any other shares of ARC Resources rankingjunior to the Second Preferred Shares with respect to priority in the paymentof dividends and in the distribution of assets in the event of the liquidation,dissolution or winding-up of ARC Resources, whether voluntary or involuntary,or any other distribution of the assets of ARC Resources among its shareholdersfor the purposeof winding-up its affairs.  As at thedate hereof, there are Second Preferred Share, Series 1 and SecondPreferred Share, Series 2 issued and outstanding which were issued to ARCSask in consideration of the transfer of properties pursuant to an internal reorganizationand which are redeemable by ARC Resources for $1,000 per share, together withall accrued and unpaid dividends.

** **

**OTHER INFORMATIONRELATING TO OUR BUSINESS**

** **

**Borrowing**

** **

Weborrow funds from time to time to finance the purchase of properties, forcapital expenditures or for other financial obligations or expenditures inrespect of properties held by us or for working capital purposes.  We have a policy relating to borrowing whichrequires a quarterly assessment by management, subject to review by the Boardof Directors of ARC Resources, of the appropriateness of borrowing levels.  We have granted security in priority to theRoyalties to secure the loan of such funds.

 

Debtservice charges on borrowed funds attributable to our properties, includingfunds borrowed by our subsidiaries from us, will be deducted in computingroyalty income. The debt repayment will be scheduled to minimize any income taxpayable by ARC Resources.

 

At December 31,2008 we had an $800 million secured, extendible, financial covenant based threeyear syndicated credit facility that expires on April 15, 2011 and a $25million demand working capital facility in addition to US

 

25

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$212 millionof senior secured notes outstanding.  Thecredit facilities and senior secured notes rank equally and contain provisionswhich restrict the ability of ARC Resources to pay Royalties and interest underthe Long Term Notes to ARC and thereby may restrict distributions toUnitholders, in the event of the occurrence of certain events of default.  The credit agreement and note agreements aredescribed under “Material Contracts” and have been filed on SEDAR atwww.sedar.com.  For more information,reference is made to Note 10 of our audited consolidated financial statementsfor the year ended December 31, 2008, which is incorporated by referencein this Annual Information Form and which has been filed on SEDAR atwww.sedar.com.

 

See “RiskFactors — Refinancing Risk and Debt Service” and “Risk Factors — Variations inInterest Rates and Foreign Exchange Rates”.

 

**OUR INFORMATION**

** **

**Trust Units**

** **

Amaximum of 650,000,000 Trust Units have been created and may be issued pursuantto the Trust Indenture.  The Trust Unitsrepresent equal undivided beneficial interests in the Trust. All Trust Unitsshare equally in all distributions made by us and all Trust Units carry equalvoting rights at meetings of Unitholders. No Unitholder will be liable to pay any further calls or assessments inrespect of the Trust Units.  Noconversion, retraction, redemption or pre-emptive rights attach to the TrustUnits.

 

**Special VotingUnit**

** **

TheTrust Indenture also provides for the issuance of special voting units whichare to be issued to a trustee and which are entitled to such number of votes atmeetings of Unitholders equal to the number of Trust Units reserved forissuance that such special voting units represent, such number of votes and anyother rights or limitations prescribed by the Board of Directors of ARCResources when the Board authorizes issuing such special voting units.

 

ASpecial Voting Unit has been designated by the Board of Directors of ARCResources as the Special Voting Unit, Exchangeable Shares (“**Special Voting Unit**”).  The Special Voting Unit possesses a number ofvotes for the election of directors of ARC Resources and on all other matterssubmitted to a vote of Unitholders equal to the number of outstandingExchangeable Shares from time to time not owned by Trust or ARC Subco.  The holders of Trust Units and the holder ofthe Special Voting Unit vote together as a single class on all matters.

 

In theevent of any liquidation, dissolution or winding-up of Trust, the holder of theSpecial Voting Unit will not be entitled to receive any of our assets availablefor distribution to Unitholders.  Theholder of the Special Voting Unit will not be entitled to receivedividends.  The Special Voting Unit hasbeen issued to Computershare Trust Company of Canada, as trustee.  At such time as the Special Voting Unit hasno votes attached to it because there are no Exchangeable Share outstandingthat are not owned by Trust or ARC Subco, the Special Voting Unit will becancelled.

 

Formore information, see “Share Capital of ARC Resources — Exchangeable Shares”.

 

**The TrustIndenture**

** **

TheTrust Indenture, among other things, provides for the calling of meetings ofUnitholders, the conduct of business thereof, notice provisions, theappointment and removal of the Trustee and the form of Trust Unitcertificates.  The Trust Indenture may beamended from time to time. Substantive amendments to the Trust Indenture,including early termination of the Trust and the sale or transfer of theproperty of the Trust as an entirety or substantially as an entirety requiresapproval by Special Resolution of Unitholders. Any approval or consent of Unitholders in relation to any matterrequired by any regulatory body will require a majority of, or such other levelof approval of Unitholders as may be stipulated by such regulatory authority,including as to the exclusion of interested or other Unitholders in thecalculation of such level of approval. See “Meetings and Voting”.

 

Thefollowing is a summary of certain provisions of the Trust Indenture.  For a complete description of such indenture,reference should be made to the Trust Indenture, a copy of which has been filedon SEDAR at www.sedar.com, or may be obtained from the Trustee.

 

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**Trustee**

** **

ComputershareTrust Company of Canada is the trustee of the Trust and also acts as thetransfer agent for the Trust Units.  TheTrustee is responsible for, among other things: (a) acceptingsubscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintainingbooks and records of the Trust and providing timely reports to holders of TrustUnits; and (c) paying distributions to Unitholders.  The Trust Indenture provides that the Trusteeshall exercise its powers and carry out its functions thereunder as Trusteehonestly, in good faith and in the best interests of the Trust and Unitholdersand, in connection therewith, shall exercise that degree of care, diligence andskill that a reasonably prudent trustee would exercise in comparablecircumstances.

 

Theterm of the Trustee’s appointment is until the next annual meeting ofUnitholders.  At each annual meeting theTrustee may be reappointed or changed as determined by a majority of the votescast at such meeting of Unitholders.  TheTrustee may resign upon 60 days’ notice to the Trust.  The Trustee may also be removed by a SpecialResolution of the Unitholders.  Suchresignation or removal becomes effective upon the acceptance or appointment ofa successor trustee.

 

ARCResources presently administers the Trust on behalf of the Trustee.  ARC Resources, on behalf of the Trustee,keeps such books and records as are necessary for the proper recording of thebusiness transactions of the Trust.

 

TheTrust Indenture provides that the Trustee shall be under no liability for anyaction or failure to act unless such liabilities arise out of the Trustee’sgross negligence, wilful default or fraud. The Trustee, where it has met its standard of care, shall be indemnifiedout of the assets of the Trust for any taxes or other government chargesimposed upon the Trustee in consequence of its performance of its duties butshall have no additional recourse against Unitholders.  In addition, the Trust Indenture containsother customary provisions limiting the liability of the Trustee.

 

**Distributionsand Allocations of Trust Income**

** **

TheTrust Indenture provides that all of the distributable income of the Trust atthe end of any calendar month including December 31 shall be declaredpayable and distributed to the Unitholders of record on the last day of eachsuch calendar month.  The distribution bythe Trust of such distributable income is enforceable by such Unitholders ofrecord.  This distributable income isallocated to Unitholders for tax purposes.

 

Inaddition, the Trust Indenture provides that such distributable income may bepaid in whole or in part by cash, in Trust Units, or promissory notes payablein whole or in part in cash or Trust Units on a specified date not more than 90days after the record date to which the promissory note relates.  The Trust Indenture also provides for theconsolidation of the Trust Units in the discretion of the Board of Directors ofARC Resources to the pre-distribution number of Trust Units after any pro-ratadistribution of additional Trust Units to all Unitholders.

 

Formore information, see “Risk Factors — Allocations of Trust Income”.

 

**FutureOfferings**

** **

Underthe Trust Indenture, the Trust may offer additional Trust Units or rights toacquire additional Trust Units at such times and on such terms as the Board ofDirectors of ARC Resources may determine. At the option of the Trust, the net proceeds from any offerings may beused to finance the acquisition of additional properties, make additional capitalexpenditures or to repay indebtedness incurred in connection with suchacquisitions.  See “Risk Factors —Capital Markets”.

 

**Meetings andVoting**

** **

Therewill be at least one meeting of Unitholders held annually.  Special meetings of Unitholders may be calledat any time by the Trustee and shall be called by the Trustee upon the writtenrequest of Unitholders holding in aggregate not less than 20 per cent of theTrust Units.  Notice of all meetings ofUnitholders shall be given to Unitholders at least 21 days prior to themeeting.

 

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Unitholderswill be entitled at each annual meeting to appoint the Trustee, to appoint theauditors of the Trust and to elect all the members of the Board of Directors ofARC Resources.

 

**Our Management**

** **

TheTrust Indenture provides for delegation to ARC Resources by the Trustee ofbroad discretion to administer and manage our day to day operations, whichincludes responsibility and authority to make executive decisions on behalf ofall of our direct or indirect subsidiaries and to exercise the powers of theTrustee.  Without limitation of theforegoing, ARC Resources has been specifically delegated to provide certainadministrative and support services to us, including those necessary: (i) toensure compliance with continuous disclosure obligations under applicablesecurities legislation; (ii) to provide investor relations services; (iii) toprovide or cause to be provided to Unitholders all information to whichUnitholders are entitled under the Trust Indenture; (iv) to call, hold anddistribute materials including notices of meetings and information circulars inrespect of all necessary meetings of Unitholders; (v) to determine theamounts payable from time to time to Unitholders and to arrange fordistributions to Unitholders of distributable income; and (vi) todetermine the timing and terms of future offerings of Trust Units, if any.

 

ARCResources has accepted all such delegation and has agreed that, in respect ofsuch matters, it shall carry out its functions honestly, in good faith and inour best interests and the best interests of Unitholders and, in connectiontherewith, shall exercise that degree of care, diligence and skill that areasonably prudent person would exercise in comparable circumstances.

 

**Limitation onNon-Resident Ownership**

** **

TheTrust intends to comply with the requirements under the Tax Act for “unittrusts” and “mutual fund trusts” at all relevant times such that we maintainour status of a unit trust and a mutual fund trust for purposes of the TaxAct.  In this regard, we may, from timeto time, among other things, take all necessary steps to monitor the activitiesof the Trust and ownership of the Trust Units. If at any time we become aware that the activities of the Trust andownership of the Trust Units by non-residents (non-residents of Canada andpartnerships) may threaten the status of the Trust under the Tax Act as a “unittrust” or “mutual fund trust”, we are authorized to take such action as may benecessary in the opinion of ARC Resources to maintain the status of the Trustas a unit trust and a mutual fund trust, including the imposition ofrestrictions on the issuance by the Trust, or the transfer by any Unitholder,of Trust Units to a non resident. See “Risk Factors — Changes in Legislation”, “RiskFactors — Non-Resident Ownership of Trust Units” and “Risk Factors — AdditionalRisk Factors Applicable to Residents of the United States and OtherNon-Residents of Canada”.

 

**Right ofRedemption**

** **

TrustUnits will be redeemable at any time on demand by the holders thereof upondelivery to us of the certificate or certificates representing such TrustUnits, accompanied by a duly completed and properly executed notice requestingredemption.  Upon receipt of theredemption request, all rights to and under the Trust Units tendered forredemption shall be surrendered and the holder thereof shall be entitled toreceive a price per Unit (“**Market RedemptionPrice**”) equal to the lesser of: (i) 90 per cent of the marketprice, being the weighted average trading price of the Trust Units on theprincipal market on which the Trust Units are quoted for trading during the 10trading day period commencing immediately after the date on which the TrustUnits are surrendered for redemption; and (ii) the closing market price onthe principal market on which the Trust Units are quoted for trading on thedate that the Trust Units are surrendered for redemption.

 

Theaggregate cash Market Redemption Price payable by us in respect of any TrustUnits surrendered for redemption during any calendar month shall be satisfiedby way of a cash payment on the last day of the following month; provided thatthe entitlement of Unitholders to receive cash upon the redemption of theirTrust Units is subject to a number of conditions, including the condition thatthe total amount payable by us in respect of such Trust Units and all otherTrust Units tendered for retraction in the same calendar month must not exceed$100,000 provided that we may waive such condition in respect of any calendarmonth.

 

If aUnitholder is not entitled to receive cash upon the redemption of Trust Unitsthen we shall, at the discretion of the Board of Directors of ARC Resources,pay the Market Redemption Price by distributing either: (i) unsecured

 

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subordinatedpromissory notes bearing interest at 4.5 per cent with a 20 year term, or (ii) distributinga portion of some or all of the assets of ARC having in the opinion of theBoard of Directors of ARC Resources a fair market value equal to the MarketRedemption Price.  Alternatively, theBoard of Directors of ARC Resources may decide to distribute a pro rata shareof the assets of the Trust, net of any liabilities of the Trust.

 

It isanticipated that the foregoing retraction right will not be the primarymechanism for holders of Trust Units to dispose of their Trust Units.  ARC Resources Notes which may be distributed *in specie* to Unitholders in connectionwith a redemption will not be listed on any stock exchange and no market isexpected to develop in the ARC Resources Notes. ARC Resources Notes may be subject to resale restrictions underapplicable securities laws.  ARC ResourcesNotes so distributed may be qualified investments for trusts governed by registeredretirement savings plans, registered retirement income trusts and deferredprofit sharing plans.  See “Risk Factors —Return of Capital and Right of Redemption.”

 

**Termination ofthe Trust**

** **

Unitholdersmay vote to terminate the Trust at any meeting of Unitholders, subject to thefollowing: (a) a vote may only be held if requested in writing by theholders of not less than 20 per cent of the Trust Units; (b) a quorum of50 per cent of the issued and outstanding Trust Units is present in person orby proxy; and (c) the termination must be approved by Special Resolutionof Unitholders.

 

Unlessthe Trust is terminated or extended by vote of Unitholders earlier, the Trusteeshall commence to wind-up the affairs of the Trust on December 31, 2095.In the event that the Trust is wound-up, the Trustee will liquidate all theassets of the Trust, pay, retire, discharge or make provision for some or allobligations of the Trust and then distribute the remaining proceeds of sale toUnitholders.

 

**Reporting toUnitholders**

** **

Ourfinancial statements will be audited annually by an independent recognized firmof chartered accountants.  Our auditedfinancial statements, together with the report of such chartered accountants,will be mailed to Unitholders and the unaudited interim financial statements ofthe Trust will be mailed to Unitholders as prescribed by securitieslegislation.  Our year end is December 31.  We are subject to the continuous disclosureobligations under all applicable securities legislation.

 

Unitholdersare entitled to inspect, during normal business hours, at the offices of theTrustee, and, upon payment of reasonable reproduction costs, to receivephotocopies of certain material contracts, the Trust Indenture and a listing ofthe registered holders of Trust Units.

 

**DistributionReinvestment and Optional Trust Unit Purchase Plan**

** **

A planhas been established to provide Unitholders who are residents of Canada (withinthe meaning of the *Tax Act*) witha method to reinvest distributions by purchasing additional Trust Units.

** **

**CORPORATE GOVERNANCE**

 

**General**

** **

Ingeneral, ARC Resources has been delegated substantially all of our managementdecisions.  Unitholders are entitled toelect all of the Board of Directors of ARC Resources pursuant to the terms ofthe Trust Indenture.  The Articles of ARCResources were amended on March 20, 2008 to provide that the Board ofDirectors of ARC Resources shall consist of a minimum of three and a maximum of12 directors.

 

**TrustIndenture**

** **

Pursuantto the Trust Indenture, Unitholders are entitled to direct the manner in whichwe will vote our shares in ARC Resources at all meetings in respect of matters,relating to the election of the directors of ARC Resources, approving itsfinancial statements and appointing auditors of ARC Resources who shall be thesame as our auditors.  Prior toexercising our voting rights in ARC Resources, each Unitholder is entitled tovote on the basis of one vote

 

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perTrust Unit held, and we are required to vote our shares in ARC Resources inaccordance with the result of the vote of Unitholders.

 

**Decision Making**

 

TheBoard of Directors of ARC Resources has a mandate to supervise the managementof our business and affairs and to act with a view to our best interests.  The Board of Directors of ARC Resourcessupervises the management of the business and affairs of our subsidiaries.  The Board of Directors’ mandate includes: (a) theresponsibility for managing our affairs; (b) monitoring our management andour activities; (c) reviewing strategic operating, capital and financialplans; and (d) compliance reporting and corporate communications.  In particular, significant operationaldecisions and all decisions relating to: (i) the acquisition anddisposition of properties for a purchase price or proceeds in excess of anamount prescribed from time to time by the Board of Directors; (ii) theapproval of capital expenditure budgets; and (iii) establishment of creditfacilities are made by the Board of Directors of ARC Resources.  In addition, the Trustee has delegated broaddiscretion in relation to our day to day operations to the Board of Directorsof ARC Resources including all decisions relating to:  (i) matters relating to any offers forTrust Units; (ii) issuances of additional Trust Units; and (iii) thedetermination of the amount of distributable income.  Any amendment to the royalty agreementsrequires the approval of the Board of Directors of ARC Resources on our behalf.  The Board of Directors of ARC Resources holdsregularly scheduled meetings at least quarterly to review the business andaffairs of our subsidiaries and make any necessary decisions relating thereto.

 

TheTrust Indenture gives to the Board of Directors of ARC Resources the authorityto exercise the rights, powers and privileges for all matters relating to themaximization of Unitholder value in the context of an offer including anyUnitholder rights protection plan, any defensive action to an offer, anydirectors circular in response to an offer, any regulatory or court proceedingrelating to an offer and any related or ancillary matter.

 

**Board of Directors of ARCResources**

 

ARCResources has a Board of Directors consisting of eight individuals, all of whomhave been elected by Unitholders, including by the holders of the ExchangeableShares through the Special Voting Unit.

 

Thename, municipality of residence, position held and principal occupation of eachdirector and officer of ARC Resources as at December 31, 2008 are set outbelow:

 
| **Name and********Municipality of Residence**                            | ** ** | **Offices Held********and Time as Director**                             | ** ** | **Principal Occupation**                                                     |
|--------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|------------------------------------------------------------------------------|
| ** **                                                               | ** ** | ** **                                                               | ** ** | ** **                                                                   |
| Mac  H. Van Wielingen(3)(4)(5)  Calgary,  Alberta, Canada           |       | Chairman  of the Board and Director  since May 3, 1996              |       | Co-Chairman  of ARC Financial Corporation (an investment management company) |
|                                                                     |       |                                                                     |       |                                                                         |
| Walter DeBoni(1) (3) (5)  Calgary,  Alberta, Canada            |       | Vice Chairman and Director  since June 26, 1996                     |       | Independent Businessman                                                      |
|                                                                     |       |                                                                     |       |                                                                         |
| John  P. DielwartCalgary, Alberta, Canada                                |       | President,  Chief Executive Officer and  Director since May 3, 1996 |       | President  and Chief Executive Officer of ARC Resources                      |
|                                                                     |       |                                                                     |       |                                                                         |
| Fred  J. Dyment(1)(2)(3)  Calgary,  Alberta, Canada                      |       | Director  since April 17, 2003                                      |       | Independent  Businessman                                                     |
|                                                                     |       |                                                                     |       |                                                                         |
| James  C. Houck(1)(2)(6)  Calgary,  Alberta, Canada                      |       | Director  since February 14, 2008                                   |       | President  and Chief Executive Officer of The Churchill Corporation          |
|                                                                     |       |                                                                     |       |                                                                         |
| Michael  M. Kanovsky(2)(3)(4)  Calgary, Alberta, Canada                  |       | Director  since May 3, 1996                                         |       | Independent  Businessman                                                     |
|                                                                     |       |                                                                     |       |                                                                         |
| Herbert  C. Pinder, Jr.(4)(5)(6)  Saskatoon,  Saskatchewan,  Canada |       | Director  since January 1, 2006                                     |       | Independent  Businessman                                                     |

 

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| **Name and********Municipality of Residence**           | ** ** | **Offices Held********and Time as Director**                | ** ** | **Principal Occupation**                                                           |
|---------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------------------------------------------------------------------------------|
| ** **                                              | ** ** | ** **                                                  | ** ** | ** **                                                                         |
| John  M. Stewart(1)(4)(6)  Scottsdale,  Arizona, U.S.A. |       | Director  since February 11, 1998                      |       | Vice  Chairman of ARC Financial Corporation (an investment management company)     |
|                                                    |       |                                                        |       |                                                                               |
| Doug  J. BonnerCalgary, Alberta, Canada                 |       | Senior  Vice-President, Corporate Development               |       | Senior  Vice-President, Corporate Development of ARC Resources                     |
|                                                    |       |                                                        |       |                                                                               |
| David  P. CareyCalgary, Alberta, Canada                 |       | Senior  Vice-President, Capital Markets                     |       | Senior  Vice-President, Capital Markets of ARC Resources                           |
|                                                    |       |                                                        |       |                                                                               |
| Terry  GillCalgary, Alberta, Canada                     |       | Senior  Vice-President, Corporate Services                  |       | Senior  Vice-President, Corporate Services of ARC Resources                        |
|                                                    |       |                                                        |       |                                                                               |
| Steven  W. SinclairCalgary, Alberta, Canada             |       | Senior  Vice-President, Finance and Chief Financial Officer |       | Senior  Vice-President, Finance and Chief Financial Officer of ARC Resources       |
|                                                    |       |                                                        |       |                                                                               |
| Myron  M. StadnykCalgary, Alberta, Canada               |       | Senior  Vice-President and Chief Operating Officer          |       | Senior  Vice-President and Chief Operating Officer of ARC Resources                |
|                                                    |       |                                                        |       |                                                                               |
| Terry  M. AndersonCalgary, Alberta, Canada              |       | Vice-President,  Operations                                 |       | Vice-President,  Operations of ARC Resources                                       |
|                                                    |       |                                                        |       |                                                                               |
| Yvan  ChrétienCalgary, Alberta, Canada             |       | Vice-President,  Land                                       |       | Vice-President,  Land of ARC Resources                                             |
|                                                    |       |                                                        |       |                                                                               |
| Ingram  B. GillmoreCalgary, Alberta, Canada             |       | Vice-President,  Engineering                                |       | Vice-President,  Engineering of ARC Resources                                      |
|                                                    |       |                                                        |       |                                                                               |
| Neil  GroeneveldCalgary, Alberta, Canada                |       | Vice-President,  Geosciences                                |       | Vice-President,  Geosciences of ARC Resources                                      |
|                                                    |       |                                                        |       |                                                                               |
| P.  Van R. DafoeCalgary, Alberta, Canada                |       | Vice-President  and Treasurer                               |       | Vice-President  and Treasurer of ARC Resources                                     |
|                                                    |       |                                                        |       |                                                                               |
| Allan  R. TwaCalgary, Alberta, Canada                   |       | Secretary                                                   |       | Partner,  Burnet, Duckworth & Palmer LLP (barristers and solicitors) |

 

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Notes:

(1)                                  Member ofAudit Committee in 2008.

(2)                                  Member ofReserves Committee in 2008.

(3)                                  Member ofRisk Committee in 2008.

(4)                                  Member ofHuman Resources and Compensation Committee in 2008.

(5)                                  Member ofPolicy and Board Governance Committee in 2008.

(6)                                  Member ofHealth, Safety and Environment Committee in 2008.

 

Withthe exception of the following individuals, the officers and directors haveheld the position set forth as his principal occupation for the last fiveyears:  Prior to 2005, Walter DeBoni, wasVice-President, Canada Frontier & International Business of HuskyEnergy Inc. (a public oil and gas company). Prior to October 2007, Mr. James Houck was President and ChiefExecutive Officer and a director of Western Oil Sands Ltd. and prior to April 1,2005, Mr. Houck held several senior positions with Chevron TexacoInc.  Prior to November 2005, StevenW. Sinclair, was Vice-President, Finance and Chief Financial officer, David P.Carey was Vice-President, Business Development, Doug Bonner was Vice-President,Engineering, Myron J. Stadnyk, was Vice-President, Operations and Land andprior to September 2004 was Vice President Operations, of ARCResources.  Prior to March 2005, P.Van R. Dafoe, was Controller of ARC Resources and prior to July 2007 wasTreasurer of ARC Resources.  Prior to November 2005,Terry M. Anderson, was Manager, Field Operations of ARC Resources, and YvanChretien was Land Manager of ARC Resources. Prior to January 2007, Ingram Gillmore was Engineering Manager ofARC Resources.  Prior to September 2008,Terry Gill, was Senior Vice President Human Resources at Superior Propane.  Prior to October 2008, Neil Groeneveldwas Manager, Geology of ARC Resources.

 

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Thefollowing comprises a brief description of the background of the officers ofARC Resources.

 

***John P.Dielwart, B.Sc., P.Eng.***

 

Mr. Dielwartwas the President and Chief Executive Officer of ARC Resources Ltd. until February 11,2009 and is now Chief Executive Officer of ARC Resources Ltd. and has overallmanagement responsibility for the Trust. Prior to joining ARC in 1996, Mr. Dielwartspent 12 years with a major Calgary based oil and natural gas engineeringconsulting firm, as senior vice-president and a director, where he gainedextensive technical knowledge of oil and natural gas properties in western Canada.He began his career working for five years with a major oil and natural gascompany in Calgary. Mr. Dielwart is a Past-Chairman of the board ofgovernors for the Canadian Association of Petroleum Producers (CAPP). He holdsa Bachelor of Science with Distinction (Civil Engineering) degree, Universityof Calgary. He has also been a director of ARC since 1996.

 

***Steven W.Sinclair, B. Comm., CA***

 

Mr. Sinclairis Senior Vice-President Finance and Chief Financial Officer of ARC ResourcesLtd. and oversees all of the financial and accounting affairs of ARC EnergyTrust. Mr. Sinclair has a Bachelor of Commerce from the University ofCalgary, and a Chartered Accountant’s designation which he received in 1981. Hehas over 25 years experience within the finance, accounting and taxation areasof the oil and gas industry and has been with the Trust since 1996. Mr. Sinclairis also a member of the Alberta and Canadian Institutes of CharteredAccountants.

 

***Myron M.Stadnyk, P.Eng.***

 

Mr. Stadnykwas the Senior Vice-President and Chief Operating Officer of ARC Resources Ltd.until February 11, 2009 and is now the President and Chief OperatingOfficer of ARC Resources Ltd. and is responsible for all aspects of ARC’songoing operational and production management and strategies. He has over 25years experience in the oil and gas business. Prior to joining ARC ResourcesLtd. in 1997, Mr. Stadnyk worked with a major oil and gas company in bothdomestic and international operations. He has a B.Sc. in Mechanical Engineeringfrom the University of Saskatchewan and is a member of the Association ofProfessional Engineers.

 

***Doug J.Bonner, P.Eng.***

 

Mr. Bonneris Senior Vice-President, Corporate Development of ARC Resources Ltd. and isresponsible for the strategic development of ARC’s enhanced oil recoveryassets. He holds a B.Sc. in Geological Engineering from the University ofManitoba. Mr. Bonner’s major area of expertise is reservoir engineeringand he has extensive technical knowledge of oil and natural gas fieldsthroughout western Canada, the east coast and northern Canada. Prior to joiningARC in 1996, Mr. Bonner spent 18 years with various major oil and naturalgas companies in positions of increasing responsibility.

 

***David P.Carey, P.Eng., MBA***

 

Mr. Careyis Senior Vice-President, Capital Markets of ARC Resources Ltd. and isresponsible for all facets of investor relations and corporate governance. Heholds both a B.Sc. in Geological Engineering and a MBA from Queen’s University.Mr. Carey brings over 25 years of diverse experience in the Canadian andInternational energy industries covering exploration, production and projectevaluations in western Canada, oil sands, the Canadian frontiers andinternationally. Prior to joining ARC Resources in 2001, Mr. Carey heldsenior positions with Athabasca Oil Sands Trust and a major Canadian oil andgas company.

 

***Terry Gill,B.PE.***

 

Mr. Gillis Senior Vice-President, Corporate Services of ARC Resources Ltd. and overseesall human resources, information technology and office services relatedactivities. Prior to joining ARC in September 2007, Mr. Gill spenteight years with a major national distribution company as a senior executive.He also spent 15 years in the oil and gas industry and has broad experience inall areas of talent management. Mr. Gill has coached high performanceathletes at an elite level and holds a B.PE. in coaching leadership from theUniversity of Alberta.

 

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***Terry M.Anderson, P.Eng.***

 

Mr. Andersonis Vice-President, Operations of ARC Resources Ltd. and is responsible for allof ARC’s operational activities. He has a B.Sc. in Petroleum Engineering and isa member of the Association of Professional Engineers in Alberta, Saskatchewanand British Columbia. Mr. Anderson has over 15 years of experience indrilling, completion, pipeline, facility and production operations.  Prior to joining ARC in 2000, he worked at amajor oil and gas company.

 

***YvanChretien, B.Comm.***

 

Mr. Chretienis Vice-President, Land of ARC Resources Ltd. and is responsible for all of ARC’sland related activities. He has over 15 years of related experience in the oiland gas business.  Prior to joining ARCin 2001, Mr Chretien worked for both senior and intermediate oil and gascompanies.

 

***Ingram B.Gillmore, P.Eng.***

 

Mr. Gillmoreis Vice-President, Engineering of ARC Resources Ltd. and is responsible for allof ARC’s engineering and joint venture related activities. He holds a B.Sc. inChemical engineering from the University of Waterloo (1991) and a Bachelor ofFine Arts. Mr. Gillmore has been at ARC since 2002. Prior to joining ARC, Mr. Gillmoreheld positions with several major oil and gas companies.

 

***NeilGroeneveld, P. Geol.***

 

Mr. Groeneveldis Vice-President, Geosciences of ARC Resources Ltd. and is responsible for ARC’sgeophysical and geological activities. He has over 20 years of experience inthe western Canadian oil & gas business and brings a broad backgroundin oil and gas development, exploration and operations. He holds a Master ofScience degree in Geology from the University of Regina. Prior to joining ARCin 2003, Mr. Groeneveld held senior positions with large and intermediateoil and gas companies.

 

***P. Van R.Dafoe, B. Comm., CMA***

 

Mr. Dafoeis Vice-President and Treasurer of ARC Resources Ltd. and is responsible forall of ARC’s Hedging and Treasury related activities. He has a Bachelor ofCommerce — Honours from the University of Manitoba and obtained his CertifiedManagement Accountant’s designation in 1995. Mr. Dafoe joined ARC in 1999after 13 years with various companies in the finance and accounting area of theoil and gas industry.

 

***Allan R.Twa, Q.C.***

 

Mr. Twaacts as Corporate Secretary of ARC Resources Ltd. A member of the Alberta Barsince 1971, Mr. Twa is a partner in the law firm Burnet, Duckworth &Palmer LLP. Mr. Twa holds a B.A. (Political Science) from the Universityof Calgary, a LL.B. from the University of Alberta and a LL.M. from theUniversity of London, England. Over the last 30 years, Mr. Twa has beenengaged in a legal practice involving legal administration of public companiesand trusts, corporate finance, and mergers and acquisitions.

 

MacVan Wielingen is the Chairman and a Director of ARC Resources and was adirector of Gauntlet Energy Corporation which secured creditor protectionpursuant to the *Companies’ CreditorsArrangement Act* on June 17, 2003 and was subsequently acquiredby Ketch Resources Ltd. in December, 2003.

 

Allof the directors of ARC Resources were elected on May 12, 2008 to holdoffice until the next annual general meeting of ARC Resources, which isscheduled for May 20, 2009.  As at December 31,2008, the directors and officers of ARC Resources, as a group, beneficiallyowned, or controlled or directed, directly or indirectly, 807,010 Trust Unitsor approximately 0.37 per cent of the outstanding Trust Units, and 613,770Exchangeable Shares or approximately 56 per cent of the outstandingExchangeable Shares.  If all of theExchangeable Shares had been exchanged for Trust Units at the Exchange Ratio ineffect on December 31, 2008, the directors and officers of ARC Resourcesas a group would hold 2,351,673 Trust Units or approximately 1.07 per cent ofthe outstanding Trust Units as at December 31, 2008.

 

33

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See “RiskFactors – Reliance on Key Members of Management”.

 

**AUDITCOMMITTEE DISCLOSURES**

 

MultilateralInstrument 52-110 (“**MI 52-110**”)relating to audit committees has mandated certain disclosures for inclusion inthis Annual Information Form.  The textof the Audit Committee’s mandate is attached as Appendix C to this AnnualInformation Form.

 

**Members of the Audit Committee**

 

Asof December 31, 2008, the members of the Audit Committee were Fred J.Dyment, chairman, and Walt DeBoni, James C. Houck and John M. Stewart, each ofwhom is independent and financially literate within the meaning ofMI 52-110.  The following comprisesa brief summary of each member’s education and experience:

 

***Fred J.Dyment***

 

Mr. Dymenthas 30 years experience in the oil and gas business and is currently anindependent businessman. His past business career included positions asPresident and CEO for Maxx Petroleum and President and CEO of Ranger OilLimited. Mr. Dyment received a Chartered Accountant designation from theprovince of Ontario in 1972. Mr. Dyment currently sits as a Director onthe Boards of Tesco Corporation, Western Oil Sands and Transglobe EnergyCorporation.  He has been a Director ofARC since 2003.

 

***Walt DeBoni***

 

Mr. DeBoniretired from Husky Energy Inc. where he held the position of VP, CanadaFrontier & International Business. Prior to this Mr. DeBoni wasCEO of Bow Valley Energy for a number of years. In addition to his time atHusky and Bow Valley he has also held numerous top executive posts in the oiland gas industry with major corporations. Mr. DeBoni holds a B.A.Sc. Chem.Eng. from the University of British Columbia, a MBA degree with a major inFinance from the University of Calgary and is a member of the association ofProfessional Engineers, Geologists and Geophysicists of Alberta and the Societyof Petroleum Engineers. He is a past Chairman of the Petroleum Society of CIM,a past Director of the Society of Petroleum Engineers and has been a Directorof ARC Resources since 1996.

 

***James C. Houck***

 

Mr. JamesC. Houck is currently the President and Chief Executive Officer and a directorof The Churchill Corporation.  Prior to January 2009Mr. Houck was an independent businessman and prior to October 18,2007 was the President and Chief Executive Officer and a director of WesternOil Sands Ltd.  Mr. Houck has a B.Sc. from Trinity University and an MBAfrom the University of Houston.  Mr. Houckhas over 37 years of industry experience, primarily with Chevron Texaco Inc.where he held a number of senior management positions.

 

***John M. Stewart***

 

Mr. Stewart isVice-Chairman and a founder of ARC Financial Corporation.  Mr. Stewart has a B.Sc. in Engineeringfrom the University of Calgary and an MBA from the University of BritishColumbia.  Prior to ARC Financial he wasa director and Vice-President of a major investment dealer.

 

**Principal Accountant Fees andServices**

 

TheAudit Committee has not adopted specific policies and procedures for theengagement of non-audit services and pre-approves each such engagement or typeof engagement for every fiscal year.

 

Ourexternal auditor is Deloitte & Touche LLP.  The following is a summary of the externalaudit services fees by category.

 

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***Audit Fees***

 

Theaggregate fees billed by our external auditor for audit services are:

 
| 2008 |   | $ | 677,834 |   |
|------|--------|---|---------|--------|
| 2007 |   | $ | 768,375 |   |

 

***AuditRelated Fees***

 

Theaggregate fees billed by our external auditor for assurance and relatedservices that are reasonably related to the performance of the audit or reviewof the financial statements (not included in audit services fees) are:

 
| 2008 |   | $ | 36,199 |   |
|------|--------|---|--------|--------|
| 2007 |   | $ | 71,724 |   |

 

***Tax Fees***

 

Theaggregate fees billed by our external auditor for professional services formunicipal property tax compliance, tax advice and tax planning are:

 
| 2008 |   | $ | 114,013 |   |
|------|--------|---|---------|--------|
| 2007 |   | $ | 139,780 |   |
|      |        |   |         |        |  |

 

***All OtherFees***

 

Theaggregate fees billed by our external auditor for products and services notincluded under the headings:  Audit Fees,Audit Related Fees, Tax Fees and All Other Fees.

 
| 2008 |   | $ | Nil |   |
|------|--------|---|-----|--------|
| 2007 |   | $ | Nil |   |

 

**CONFLICTSOF INTEREST**

 

TheBoard of Directors has adopted a Code of Business Conduct and Ethics and a Codeof Ethics for Senior Financial Officers (the “**Codes**”).  In general, the private investment activitiesof employees, directors and officers are not prohibited, however, should anexisting investment pose a potential conflict of interest the potentialconflict is required by the Codes to be disclosed to the President or the Boardof Directors.  Any other activities ofemployees which pose a potential conflict of interest are also required by theCodes to be disclosed to the President or the Board of Directors.  Any such potential conflicts of interestswill be dealt with openly with full disclosure of the nature and extent of thepotential conflicts of interests with the Trust.

 

Itis acknowledged in the Codes that employees, officers and directors may bedirectors or officers of other entities engaged in the oil and gas business,and that such entities may compete directly or indirectly with the Trust.  No assurance can be given that opportunitiesidentified by directors of ARC Resources will be provided to us.  Passive investments in public or privateentities of less than one per cent of the outstanding shares will not be viewedas “competing” with the Trust.  Anydirector, officer or employee of ARC Resources which is a director or officerof any entity engaged in the oil and gas business shall disclose suchoccurrence to the Board of Directors. Any director, officer or employee of ARC Resources who is activelyengaged in the management of, or who owns an investment of one per cent or moreof the outstanding shares, in public or private entities shall disclose suchholding to the Board of Directors.  In theevent that any circumstance should arise as a result of such positions orinvestments being held or otherwise which in the opinion of the Board ofDirectors constitutes a conflict of interest which reasonably affects suchperson’s ability to act with a view to the best interests of the Trust, theBoard of Directors will take such actions as are reasonably required to resolvesuch matters with a view to the best interests of the Trust.  Such actions, without limitation, may includeexcluding such directors, officers or employees from certain information oractivities of the Trust.

 

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The *Business Corporations Act* (Alberta)provides that in the event that an officer or director is a party to, or is adirector or an officer of or has a material interest in any person who is aparty to, a material contract or material transaction or proposed materialcontract or proposed material transaction, such officer or director shalldisclose the nature and extent of his or her interest and shall refrain from votingto approve such contract or transaction.

 

**INTERESTOF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

 

Thereis no material interest, direct or indirect, of any director or senior officer,or to our knowledge any person or company that is the direct or beneficialowner, or who exercises control or direction over more than 10 per cent ofoutstanding Trust Units, or any associate or affiliate of any of the foregoing,in any transaction within the three most recently completed financial years.

 

**DISTRIBUTIONSTO UNITHOLDERS**

 

Thefollowing per Trust Unit distributions have been made in the last threecompleted financial years:

 
| **2006**        | ** ** | **Distribution Per Trust Unit** | ** ** |
|-----------------|------------|------------------------------------------------|------------|
| First  Quarter  |       | $                                              | 0.60       |   |
| Second  Quarter |       | $                                              | 0.60       |   |
| Third  Quarter  |       | $                                              | 0.60       |   |
| Fourth  Quarter |       | $                                              | 0.60       |   |

 
| **2007**        | ** ** | ** ** | ** ** |
|-----------------|------------|------------|------------|
| First  Quarter  |       | $          | 0.60       |   |
| Second  Quarter |       | $          | 0.60       |   |
| Third  Quarter  |       | $          | 0.60       |   |
| Fourth  Quarter |       | $          | 0.60       |   |

 
| **2008**        | ** ** | ** ** | ** ** |
|-----------------|------------|------------|------------|
| First  Quarter  |       | $          | 0.60       |   |
| Second  Quarter |       | $          | 0.68       |   |
| Third  Quarter  |       | $          | 0.80       |   |
| Fourth  Quarter |       | $          | 0.59       |   |

 

Incertain circumstances, distributions may be restricted by our borrowingagreements.  For more information see “OtherInformation Relating to Our Business – Borrowing”.  Distributions paid to Unitholders in 2006were two per cent tax deferred, 2007 distributions were three per cent taxdeferred and 2008 distributions were two per cent tax deferred.  For more information, see “Our Business—Distributions and Distribution Policy”.

 

**PRICERANGE AND TRADING VOLUME OF TRUST UNITSAND EXCHANGEABLE SHARES**

 

TheTrust Units are listed and posted for trading on the TSX.  The trading symbol for the Trust Units isAET.UN.  The following table sets forththe high and low closing prices and the aggregate volume of trading of theTrust Units on the TSX for the periods indicated (as quoted by the TSX):

 

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| ** **           | ** ** | **Toronto Stock Exchange** | ** ** |
|----------------------|------------|--------------------------------------|------------|
| **2008 Period** | ** ** | **High**                             | ** ** | **Low** | ** ** | **Volume** | ** ** |
|                 |       | **$**                                |       | **$** |   |   |   |
| January              |       | 22.35                                |       | 19.30 |   | 15,607,492 |   |
| February             |       | 24.49                                |       | 21.50 |   | 17,999,702 |   |
| March                |       | 27.19                                |       | 22.97 |   | 20,477,332 |   |
| April                |       | 28.12                                |       | 24.84 |   | 13,428,991 |   |
| May                  |       | 31.57                                |       | 25.40 |   | 16,885,970 |   |
| June                 |       | 34.02                                |       | 28.90 |   | 11,815,283 |   |
| July                 |       | 34.47                                |       | 27.49 |   | 17,391,202 |   |
| August               |       | 30.40                                |       | 27.98 |   | 14,746,900 |   |
| September            |       | 29.49                                |       | 21.99 |   | 20,159,234 |   |
| October              |       | 23.10                                |       | 14.14 |   | 39,453,166 |   |
| November             |       | 20.70                                |       | 16.56 |   | 22,175,682 |   |
| December             |       | 20.10                                |       | 14.88 |   | 33,877,468 |   |

 

TheExchangeable Shares are listed and posted for trading on the TSX.  The trading symbol for the ExchangeableShares is ARX.  The following table setsforth the high and low closing prices and the aggregate volume of trading ofthe Exchangeable Shares on the TSX for the periods indicated (as quoted by theTSX):

 
| ** **           | ** ** | **Toronto Stock Exchange** | ** ** |
|----------------------|------------|--------------------------------------|------------|
| **2008 Period** | ** ** | **High**                             | ** ** | **Low** | ** ** | **Volume** | ** ** |
| ** **           | ** ** | **$**                                |       | **$** |   |   |   |
| January              |       | 50.00                                |       | 45.00 |   | 1,000 |   |
| February             |       | 54.00                                |       | 52.50 |   | 1,400 |   |
| March                |       | 62.50                                |       | 51.01 |   | 2,377 |   |
| April                |       | 66.00                                |       | 60.40 |   | 1,600 |   |
| May                  |       | 72.03                                |       | 67.00 |   | 10,606 |   |
| June                 |       | 75.70                                |       | 71.00 |   | 5,300 |   |
| July                 |       | 80.00                                |       | 69.50 |   | 3,200 |   |
| August               |       | 71.80                                |       | 68.05 |   | 2,633 |   |
| September            |       | 72.50                                |       | 54.88 |   | 6,109 |   |
| October              |       | 56.00                                |       | 37.00 |   | 7,500 |   |
| November             |       | 48.00                                |       | 48.00 |   | 300 |   |
| December             |       | 48.00                                |       | 46.60 |   | 1,100 |   |

 

**INDUSTRYREGULATIONS**

 

Theoil and natural gas industry is subject to extensive controls and regulationsgoverning its operations (including land tenure, exploration, development,production, refining, transportation, and marketing) imposed by legislationenacted by various levels of government and with respect to pricing andtaxation of oil and natural gas by agreements among the governments of Canada,Alberta, British Columbia, and Saskatchewan, all of which should be carefullyconsidered by investors in the oil and gas industry.  It is not expected that any of these controlsor regulations will affect our operations in a manner materially different thanthey would affect other oil and gas companies of similar size.  All current legislation is a matter of publicrecord and we are unable to predict what additional legislation or amendmentsmay be enacted.  See “Risk Factors —Changes in Legislation” and “Risk Factors — Regulatory.” Outlined below aresome of the principal aspects of legislation, regulations and agreementsgoverning the oil and gas industry.

 

**Pricing and Marketing - Oiland Natural Gas**

 

Theproducers of oil are entitled to negotiate sales contracts directly with oilpurchasers, with the result that the market determines the price of oil.  Oil prices are primarily based on worldwidesupply and demand.  The specific pricedepends in part on oil quality, prices of competing fuels, distance to themarkets, the value of refined products, the supply/demand balance, and othercontractual terms.  Oil exporters arealso entitled to enter into export contracts with terms not exceeding one yearin the case of light crude oil and two years in the case of heavy crude oil,provided that an order approving such export has been obtained from theNational Energy Board of Canada (the “**NEB**”).  Any oil export to be made pursuant to acontract of longer duration (to a maximum of 25 years) requires

 

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anexporter to obtain an export licence from the NEB and the issuance of suchlicence requires a public hearing and the approval of the Governor in Council.

 

Theprice of natural gas is determined by negotiation between buyers and sellers.  Natural gas exported from Canada is subjectto regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices andother terms with purchasers, provided that the export contracts must continueto meet certain other criteria prescribed by the NEB and the Government ofCanada.  Natural gas (other than propane,butane and ethane) exports for a term of less than two years or for a term oftwo to 20 years (in quantities of not more than 30,000 m3/day),must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longerduration (to a maximum of 25 years) or a larger quantity requires an exporterto obtain an export licence from the NEB and the issuance of such licencerequires a public hearing and the approval of the Governor in Council.

 

Thegovernments of Alberta, British Columbia, and Saskatchewan also regulate thevolume of natural gas that may be removed from those provinces for consumptionelsewhere based on such factors as reserve availability, transportationarrangements, and market considerations.

 

**Pipeline Capacity**

 

Althoughpipeline expansions are ongoing, the lack of firm pipeline capacity continuesto affect the oil and natural gas industry and limit the ability to produce andto market natural gas production.  Inaddition, the pro-rationing of capacity on the inter-provincial pipelinesystems also continues to affect the ability to export oil and natural gas.

 

**The North American Free TradeAgreement**

 

TheNorth American Free Trade Agreement (“**NAFTA**”)among the governments of Canada, United States of America, and Mexico becameeffective on January 1, 1994.  NAFTAcarries forward most of the material energy terms that are contained in theCanada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free todetermine whether exports of energy resources to the United States or Mexicowill be allowed, provided that any export restrictions do not: (i) reducethe proportion of energy resources exported relative to domestic use (basedupon the proportion prevailing in the most recent 36 month period); (ii) imposean export price higher than the domestic price subject to an exception withrespect to certain voluntary measures which only restrict the volume ofexports; and (iii) disrupt normal channels of supply.  All three countries are prohibited fromimposing minimum or maximum export or import price requirements, provided, inthe case of export price requirements, any prohibition in any circumstances inwhich any other form of quantitative restriction is prohibited, and in the caseof import-price requirements, such requirements do not apply with respect toenforcement of countervailing and anti-dumping orders and undertakings.

 

NAFTAcontemplates the reduction of Mexican restrictive trade practices in the energysector by 2010 and prohibits discriminatory border restrictions and exporttaxes.  NAFTA also contemplates clearerdisciplines on regulators to ensure fair implementation of any regulatorychanges and to minimize disruption of contractual arrangements and avoid undueinterference with pricing, marketing and distribution arrangements, which isimportant for Canadian natural gas exports.

 

**Provincial Royalties andIncentives**

 

***General***

 

In additionto federal regulation, each province has legislation and regulations whichgovern land tenure, royalties, production rates, environmental protection, andother matters.  The royalty regime is asignificant factor in the profitability of crude oil, natural gas liquids,sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiation between the mineral freehold owner and the lessee,although production from such lands is subject to certain provincial taxes androyalties.  Crown royalties aredetermined by governmental regulation and are generally calculated as apercentage of the value of the gross production.  The rate of royalties payable generallydepends in part on prescribed reference prices, well productivity, geographicallocation, field discovery date, method of recovery, and the type or quality ofthe petroleum product produced.  Otherroyalties and royalty-like interests are, from time to time, carved out of theworking interest

 

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owner’sinterest through non-public transactions. These are often referred to as overriding royalties, gross overridingroyalties, net profits interests, or net carried interests.

 

Occasionallythe governments of the western Canadian provinces create incentive programs forexploration and development.  Suchprograms often provide for royalty rate reductions, royalty holidays, and taxcredits, and are generally introduced when commodity prices are low.  The programs are designed to encourageexploration and development activity by improving earnings and cash flow withinthe industry.  Royalty holidays andreductions would reduce the amount of Crown royalties paid by oil and gasproducers to the provincial governments and would increase the net income andfunds from operations of such producers. However, the trend in recent years has been for provincial governmentsto eliminate, amend or allow such incentive programs to expire without renewal,and consequently few such incentive programs are currently operative.

 

TheCanadian federal corporate income tax rate levied on taxable income is 19.5 percent effective January 1, 2008 for active business income includingresource income.  With the elimination ofthe corporate surtax effective January 1, 2008 and other rate reductionsintroduced in the October 2007 Economic Statement and Notice of Ways andMeans Motion, 2006 Federal Budget, the federal corporate income tax rate willdecrease to 15 per cent in four additional steps: 19 per cent on January 1,2009, 18 per cent on January 1, 2010, 16.5 per cent on January 1,2011 and 15 per cent on January 1, 2012.

 

***Alberta***

 

InAlberta, companies are granted the right to explore, produce and developpetroleum and natural gas resources in exchange for royalties, bonus bidpayments and rents.  On October 25,2007, the Government of Alberta released a report entitled “The New RoyaltyFramework” (the “**NRF**”) containingthe Government’s proposals for Alberta’s new royalty regime, which was followedby the *Mines and Minerals (New RoyaltyFramework) Amendment Act*, 2008, which was given Royal Assent on December 2,2008.  The NRF and the applicable newlegislation became effective on January 1, 2009.  The NRF establishes new royalty rates forconventional oil, natural gas and oil sands. The new royalty rates for conventional oil are set by a single slidingrate formula which is applied monthly and increases the old royalty from 30 percent to 35 per cent applied to the old and new tiers, to up to 50 per cent andwith rate caps once the price of conventional oil reaches $120 per barrel.  The sliding rate formula includes in itscalculation the price of oil and well production.

 

Withrespect to natural gas, and similar to the conventional oil framework, theroyalties outlined in the NRF are set by a single sliding rate formula rangingfrom five per cent to 50 per cent with a rate cap once the price of natural gasreaches $16.59/GJ.  In response to thedrop in commodity prices experienced during the second half of 2008, theGovernment of Alberta announced on November 19, 2008, the introduction ofa five year program of transitional royalty rates with the intent of promotingnew drilling.  Under this new programcompanies drilling new natural gas or conventional oil deep wells (between1,000 and 3,500 metres) will be given a one-time option, on a well by wellbasis, to adopt either the new transitional royalty rates or those outlined inthe NRF.  In order to qualify for thisprogram wells must be drilled during the period starting on November 19,2008 and ending on December 31, 2013. Following this period all new wells drilled will automatically besubject to the NRF.

 

Oilsands projects are now subject to the NRF, and regulated, among others, by the *Oil Sands Royalty Regulation, 2009 Oil Sands AllowedCosts (Ministerial) Regulation* and the *Bitumen Valuation Methodology (Ministerial) Regulation, 2009*,all approved**by the Government ofAlberta on December 10, 2008.

 

On April 10,2008, the Government of Alberta introduced two new royalty programs that areintended to encourage the development of deep oil and gas reserves, and theseare:  (a) a five-year oil programfor exploration wells over 2,000 metres that will provide royalty adjustmentsto offset higher drilling costs and provide a greater incentive for producersto continue to pursue new, deeper oil plays (these oil wells will qualify forup to a $1 million or 12 months of royalty offsets, whichever comes first); and(b) a five-year natural gas deep drilling program that will replace theexisting program in order to encourage continued deep gas exploration for wellsdeeper than 2,500 metres (the program will create a sliding scale of royaltycredit according to depth, of up to $3,750 per metre).  These new programs are to be implementedalong with the NRF.

 

Regulationsmade pursuant to the *Mines and Minerals Act*(Alberta) provided various incentives for exploring and developing oil reservesin Alberta.  However, the AlbertaGovernment announced in August of 2006 that four royalty programs were tobe amended, a new program was to be introduced and the Alberta Royalty TaxCredit

 

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Programwas to be eliminated, effective January 1, 2007.  The programs affected by this announcementwere: (i) Deep Gas Royalty Holiday; (ii) Low Productivity WellRoyalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) HorizontalRe-Entry Royalty Reduction.  The programintroduced was the Innovative Energy Technologies Program (the “**IETP**”) which has a stated objective ofpromoting the producers’ investment in research, technology and innovation forthe purposes of improving environmental performance while creating commercialvalue.  The IETP provides royaltyreductions which are presumed to reduce financial risk.  Alberta Energy decides which projects qualifyand the level of support that will be provided. The deadline for the IETP’s final round of applications was September 20,2008.  The successful applicants for thefirst two rounds have been announced, and those for the third round selectionare scheduled to be announced in the first half of 2009.  The technical information gathered from thisprogram is to be made public once a two-year confidentiality period expires.

 

TheNRF includes a policy of “shallow rights reversion”.  The Government of Alberta started toimplement this policy on January 1, 2009, and its intent is to maximizethe development of currently undeveloped resources that is consistent with theGovernment of Alberta’s objective of maximizing recovery of known gasresources, while increasing royalty revenues. The policy’s stated objective is for the mineral rights to shallow gasgeological formations that are not being developed to revert back to theGovernment of Alberta and be made available for resale, and in the event ofnon-productive shallow wells, to sever the rights from shallow zones andencourage increased production from up-hole zones.  The shallow rights reversion policy affectsall petroleum and natural gas agreements; however, the timing of the reversionwill differ depending on whether the leases and licenses were acquired prior toJanuary 1, 2009 or subsequent to January 1, 2009.  Leases granted after January 1, 2009will be subject to shallow rights reversion at the expiry of the primary term,and in the event of a licence the policy will apply at the expiry of theintermediate term.  Holders of leases orlicences that have been continued indefinitely prior to January 1, 2009will receive a notice regarding the reversion of the shallow rights, which willbe implemented three years from the date of the notice.  The lease or licence holder can make arequest to extend this period.  The orderin which these agreements will receive the reversion notice will depend on thevintage of their term, with the older leases and licenses receiving a reversionnotice first.  Leases or licences thatwere granted prior January 1, 2009 but have not yet been continued willhave a grace period until they are continued under section 15 of the *P&G Tenure Regulation* and be subjectto deeper rights reversion prior to receiving a shallow rights reversionnotice.

 

On March 3,2009, the Government of Alberta announced a three-point incentive program tostimulate new and continued economic activity in Alberta which included adrilling royalty credit for new conventional oil and natural gas wells and anew well royalty incentive program.  Underthe drilling royalty credit program a $200 per meter royalty credit will beavailable on new conventional oil and natural gas wells drilled between April 1,2009 and March 31, 2010, subject to certain maximum amounts.  The maximum credits available will bedetermined by our Crown production level in 2008 and our drilling activitybetween April 1, 2009 and March 31, 2010.  Based on our 2008 production we will beentitled to a maximum credit of 10 per cent of royalties payable in the period April 1,2009 and March 31, 2010.  The newwell incentive program will apply to wells beginning production of conventionaloil and natural gas between April 1, 2009 and March 31, 2010 andprovides for a maximum five per cent royalty rate for the first 12 months ofproduction, up to a maximum of 50,000 barrels or 500 Mmcf of natural gas.

 

Thethree-point incentive program also includes an investment of $30,000,000 by theGovernment of Alberta in abandonment and reclamation projects for orphanwells.  The stated objective of thisinvestment is to encourage the cleanup of inactive oil and gas wells and tostimulate new activity within the services sector.

 

***BritishColumbia***

 

Producersof oil and natural gas in British Columbia are required to pay annual rentalpayments with respect to the Crown leases and royalties and freehold productiontaxes in respect of oil and natural gas produced from Crown and freeholdlands.  The amount payable as a royaltyin respect of oil depends on the type of oil, the value of the oil, thequantity of oil produced in a month, and the vintage of the oil.  Generally, the vintage of oil is based on thedetermination of whether the oil is produced from a pool discovered before October 31,1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil),or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take intoaccount the vintage of the oil, if the oil produced has already been sold andany royalty exempt value applicable (exempt wells).  Oil produced from newly discovered pools maybe exempt from the payment of a royalty for the first 36 months of productionor 11,450m3 produced, whichever comes first; and the

 

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royaltiesfor third-tier oil are the lowest reflecting the higher costs of explorationand extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scalebased on a reference price, which is the greater of the price obtained by theproducer, and a prescribed minimum price. However, when the reference price is below the select price (a parameterused in the royalty rate formula), the royalty rate is fixed.  As an incentive for the production andmarketing of natural gas, which may have been flared, natural gas produced inassociation with oil has a lower royalty then the royalty payable onnon-conservation gas.

 

On May 30,2003, the Ministry of Energy and Mines for British Columbia announced an Oiland Gas Development Strategy for the Heartlands (“**Strategy**”).  TheStrategy is a comprehensive program to address road infrastructure, targetedroyalties and regulatory reduction, and British Columbia service sectoropportunities.  In addition, the Strategywill result in economic and employment opportunities for communities in BritishColumbia’s heartlands.

 

Someof the financial incentives in the Strategy include:

 

·                                        Royaltycredits towards the construction, upgrading, and maintenance of roadinfrastructure in support of resource exploration and development.  Funding will be contingent upon an equalcontribution from industry. This program has evolved over past years as aresult of the Province’s stated objective to increase competitiveness, and on March 2,2009 the Government of British Columbia announced the 2009 InfrastructureRoyalty Credit Program (“**Program**”)which allocates $120 million in royalty credits for oil and gas companies. TheProgram provides access to royalty credits to oil and gas companies withrespect to certain approved road construction or pipeline infrastructureprojects intended to improve, or make possible, the access to new andunderdeveloped oil and gas areas. Companies must apply to the Ministry of Energy and Mines for BritishColumbia prior to 2:00 p.m. on April 30, 2009 to be considered forapproval under the program.

 

·                                        Changes toprovincial royalties: new royalty rates for low productivity natural gas toenhance marginally economic resources plays, royalty credits for deep gasexploration to locate new sources of natural gas, and royalty credits forsummer drilling to expand the drilling season.

 

TheBritish Columbia Energy Plan announced on February 27, 2007 outlines therequirements for the development of goals for conservation, energy efficiencyand clean energy.  In addition, itsstated goal is to promote competitiveness through the implementation of a NetProfit Royalty Program (“**NPRP**”)among others, and facilitate the development of the oil and gas industry.  The NPRP’s objective is to share the capitalrisk of successful developments. Pursuant to the Net Profit Royalty Regulation, the holder of a lease canapply to pay monthly net profit royalties on production of oil and for naturalgas wells within a proposed project.  Theamount paid is calculated on the producer’s interest in the project, and itranges from two per cent to five per cent of the gross revenue and 15 per centto 35 per cent of the net revenues received. In addition, it depends at which stage the well is, which may be eitherpre-payout, after-payout or already producing marketable gas.

 

TheGovernment of British Columbia has introduced a few more royalty programs, inaddition to the ones previously mentioned, including a royalty program for deepdiscovery wells, royalty programs with a stated goal of attracting investmentto less productive shallow gas wells (Ultra-Marginal Royalty Program), and theimplementation of royalty credits to assist the development of the coalbed gasreserves found in the Province of British Columbia.

 

***Saskatchewan***

 

InSaskatchewan, the amount payable as a royalty in respect of oil depends on thevintage of the oil, the type of oil, the quantity of oil produced in a month,and the value of the oil.  For Crownroyalty and freehold production tax purposes, crude oil is considered “heavyoil”, “southwest designated oil”, or “non-heavy oil other than southwestdesignated oil”.  The conventionalroyalty and production tax classifications (“fourth tier oil” introduced October 1,2002, “third tier oil”, “new oil” and “old oil”) of oil production areapplicable to each of the three crude oil types.  The Crown royalty and freehold production taxstructure for crude oil is price sensitive and varies between the base royaltyrates of five per cent for all “fourth tier oil” to 20 per cent for “old oil”.  Marginal royalty rates are 30 per cent forall “fourth tier oil” to 45 per cent for “old oil”.

 

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Theamount payable as a royalty in respect of natural gas is determined by asliding scale based on a reference price (which is the greater of the amountobtained by the producer and a prescribed minimum price), the quantity producedin a given month, the type of natural gas, and the vintage of the naturalgas.  As an incentive for the productionand marketing of natural gas which may have been flared, the royalty rate onnatural gas produced in association with oil is less than on non-associatednatural gas.  The royalty and productiontax classifications of gas production are “fourth tier gas” introduced October 1,2002, “third tier gas”, “new gas”, and “old gas”.  The Crown royalty and freehold production taxfor gas is price sensitive and varies between the base royalty rate of five percent for “fourth tier gas” and 20 per cent for “old gas”.  The marginal royalty rates are between 30 percent for “fourth tier gas” and 45 per cent for “old gas”.

 

On October 1,2002, the following changes were made to the royalty and tax regime inSaskatchewan:

 

·                                        A newCrown royalty and freehold production tax regime applicable to associatednatural gas (gas produced from oil wells) that is gathered for use or sale andis produced from: (a) oil wells with a finished drilling date on or after October 1,2002, and (b) oil wells with a finished drilling date prior to October 1,2002, where the individual oil well has a gas-oil production ratio in any monthof more than 3,500 cubic metres of gas for every cubic metre of oil.  The royalty/tax will be payable on associatednatural gas produced from an oil well that exceeds approximately 65,000 cubicmetres in a month.  The associatednatural gas royalty/tax regime will apply to gas produced from oil wellsaffected by concurrent production approvals after October 1, 2002 if theoil wells meet (a) or (b) above.

 

·                                        A modifiedsystem of incentive volumes and maximum royalty/tax rates applicable to theinitial production from oil wells and gas wells with a finished drilling dateon or after October 1, 2002, was introduced.  The incentive volumes are applicable tovarious well types and are subject to a maximum royalty rate of 2.5 per centand a freehold production tax rate of zero per cent.

 

·                                        Theelimination of the re-entry and short section horizontal oil well royalty/taxcategories.  All horizontal oil wellswith a finished drilling date on or after October 1, 2002, will receivethe “fourth tier” royalty/ tax rates and new incentive volumes.

 

·                                        Ahorizontal oil well, with a finished drilling date on or after October 1,2002, that is a non-deep oil well qualifies for a 6,000 cubic metre incentivevolume.

 

·                                        Ahorizontal oil well, with a finished drilling date on or after October 1,2002, that is a deep oil well qualifies for a 16,000 cubic metre incentivevolume.

 

In1975, the Government of Saskatchewan introduced a Royalty Tax Rebate (“**RTR**”) as a response to the Government ofCanada disallowing Crown royalties and similar taxes as a deductible businessexpense for income tax purposes.  As of January 1,2007, the remaining balance of any unused RTR will be limited in its carryforward to seven years since the Government of Canada’s initiative toreintroduce the full deduction of provincial resource royalties from federaland provincial taxable income. Saskatchewan’s RTR will be wound down as a result of the Government ofCanada’s plan to reintroduce full deductibility of provincial resourceroyalties for corporate income tax purposes.

 

On June 19,2007, the Government of Saskatchewan introduced the Orphan Well and FacilityLiability Management Program pursuant to the amendment of the *Oil and Gas Conservation Act* and the *Oil and Gas Conservation Regulations*,1985.  The program includes a securitydeposit, which has two purposes: (i) preventing any person withinsufficient financial capability from acquiring oil and gas wells orfacilities; and (ii) in the case of a bankrupt company, the funds coverthe decommissioning and reclaiming of orphan properties.  An additional change introduced is themandatory licensing of all upstream oil and gas facilities in Saskatchewan.

 

**Land Tenure**

 

Crudeoil and natural gas located in the western provinces is owned predominantly bythe respective provincial governments. Provincial governments grant rights to explore for and produce oil andnatural gas pursuant to leases, licences, and permits for varying terms fromtwo years, and on conditions set forth in provincial legislation

 

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includingrequirements to perform specific work or make payments.  Oil and natural gas located in such provincescan also be privately owned and rights to explore for and produce such oil andnatural gas are granted by lease on such terms and conditions as may benegotiated.

 

**Environmental Regulation**

 

Theoil and natural gas industry is currently subject to environmental regulationspursuant to a variety of provincial and federal legislation.  Such legislation provides for restrictionsand prohibitions on the release or emission of various substances produced inassociation with certain oil and gas industry operations.  In addition, such legislation requires thatwell and facility sites be abandoned and reclaimed to the satisfaction ofprovincial authorities.  Compliance withsuch legislation can require significant expenditures and a breach of suchrequirements may result in suspension or revocation of necessary licenses andauthorizations, civil liability for pollution damage, and the imposition ofmaterial fines and penalties.

 

Environmentallegislation in Alberta has been consolidated into the *Environmental Protection and Enhancement Act*(Alberta)(the “**EPEA**”), which came intoforce on September 1, 1993, and the *Oiland Gas Conservation Act*(Alberta) (the “**OGCA**”). The EPEA and OGCA impose stricter environmental standards, require morestringent compliance, reporting and monitoring obligations, and significantlyincreased penalties.  In 2006, theGovernment of Alberta enacted regulations pursuant to the EPEA to specificallytarget sulphur oxide and nitrous oxide emissions from industrial operationsincluding the oil and gas industry.  Inaddition, the reduction emission guidelines outlined in the *Climate Change and Emissions Management Amendment Act*came into effect on July 1, 2007 (“**CCEMAA**”).  Under thislegislation, Alberta facilities emitting more than 100,000 tonnes of greenhousegases a year must reduce their emissions intensity by 12 per cent.  Industries have three options to choose fromin order to meet the reduction requirements outlined in this legislation, andthese are: (i) by making improvement to operations that result inreductions; (ii) by purchasing emission credits from other sectors orfacilities that have emissions below the 100,000 tonne threshold and arevoluntarily reducing their emission; or (iii) by contributing to theClimate Change and Emissions Management Fund (the “**Fund**”).  Industries caneither choose one of these options or a combination thereof.  Pursuant to CCEMAA and the *Specified Gas Emitters Regulation*,companies were obliged to reduce their emission intensity by 12 per cent by March 31,2008.  Alberta industries have achieved2.6 million tonnes of actual reduction, due to changes in operations andinvesting on verified offset projects. In addition, certain companies contributed $40 million to the Fund.  It is reasonably likely that the trendtowards stricter standards in environmental legislation and regulation willcontinue.

 

On January 24,2008, the Alberta Government announced a new climate change action plan that itbelieves will cut Alberta’s projected 400 million tonnes of emissions in halfby 2050.  This plan is based on threeareas: (i) carbon capture and storage, which will be mandatory for *in situ* oil sand facilities that use heavyfuels for steam generation; (ii) energy conservation and efficiency; and (iii) greeningproduction through increased investment in clean energy technology, includingsupporting research on new oil sands extraction processes, as well as thefunding of projects that reduce the cost of separating carbon dioxide fromother emissions supporting carbon capture and storage.  In addition to this action plan, theProvincial Energy Strategy unveiled on December 11, 2008 is expected to,among other things, support the upgrading, refining and petrochemical clustersexisting in the Province of Alberta, market Alberta’s energy internationally,review the emission targets and carbon charges applied to large facilities, andpromote the innovation of energy technology by encouraging investment inresearch and development.

 

BritishColumbia’s *Environmental Assessment Act*became effective June 30, 1995. This legislation rolls the previous processes for the review of majorenergy projects into a single environmental assessment process with publicparticipation in the environmental review process.  On February 27, 2007 the Government ofBritish Columbia unveiled the Energy Plan outlining its strategy towards theenvironment and which includes targeting for zero net greenhouse gas emissions,promoting new investments in innovation, and becoming the world’s leader insustainable environmental management. For this purpose, on December 18, 2007 proposals were sought forapplications to the Innovative Clean Energy Fund, in order to attract newtechnologies that will help solve energy and environmental issues.  With regards to the oil and natural gasindustry the objective is to achieve clean energy through conservation andenergy efficient practices, whilst competitiveness is advocated in order to attractinvestment for the development of the oil and natural gas sector.  Among the changes to be implemented are: (i) anew Net Profit Royalty Program; (ii) the creation of a Petroleum Registry;(iii) the establishment of an infrastructure royalty program (combiningroads and pipelines); (iv) the elimination of routine flaring at producingwells; (v) the creation of policies and measures for the reduction ofemissions; (vi) the development of unconventional resources such as tightgas and coalbed gas; and (vii) the Oil and Gas Technology TransferIncentive Program that encourages

 

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theresearch, development and use of innovative technologies to increase recoveriesfrom existing reserves and promotes responsible development of new oil and gasreserves.  Furthering these initiatives,the Government of British Columbia introduced on July 1, 2008,revenue-neutral carbon tax legislation that is applied to all fossil fuels usedin the Province of British Columbia.  Thetax would be phased in, and the initial rate would be based on CO2 of $10 per tonne for the first six months of2009 and $15 per tonne for the last six months of 2009, following $5 per tonneincreases on July of every year until 2012.  Tax credits and reductions will be used inorder to offset the tax revenues that the Government of British Columbia wouldreceive otherwise.  On April 3,2008, the Government of British Columbia introduced the *Greenhouse Gas Reduction (Cap and Trade) Act*which will allow participation in the Western Climate Initiative cap and tradesystems being developed.  The systemestablishes a limit on emissions, and allows regulated emitters to buy/sellemission allowances or offset emits.  Theemitter is obliged to obtain emission allowances (compliance units) equal to theamount of greenhouse gases emitted within a certain period of time, and thatare supposed to be surrendered to the Government of British Columbia ascompliance proof.

 

In December 2002,the Government of Canada ratified the Kyoto Protocol (“**Kyoto Protocol**”).  The Kyoto Protocol calls for Canada to reduceits greenhouse gas emissions to six per cent below 1990 “business-as-usual”levels between 2008 and 2012.  Givenrevised estimates of Canada’s normal emissions levels, this target translatesinto an approximately 40 per cent gross reduction in Canada’s currentemissions.  It is questionable, based onthe Updated Action Plan announced by the Federal Government (see below), thatthe Kyoto Protocol target of six per cent below 1990 emission levels will be enforcedin Canada.  Bill C-288, which is intendedto ensure that Canada meets its global climate change obligations under theKyoto Protocol, was passed by the House of Commons on February 14,2007.  On April 26, 2007, theFederal Government released its Action Plan to Reduce Greenhouse Gases and AirPollution (the “**Action Plan**”) alsoknown as ecoACTION which includes the regulatory framework for airemissions.  This Action Plan covers notonly large industry, but regulates the fuel efficiency of vehicles and thestrengthening of energy standards for a number of energy using products.

 

TheGovernment of Canada and the Province of Alberta released on January 31,2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture andStorage Task Force, which recommends among others: (i) incorporatingcarbon capture and storage into Canada’s clean air regulations; (ii) allocatingnew funding into projects through competitive process; and (iii) targetingresearch to lower the cost of technology.

 

Inorder to strengthen the Action Plan, on March 10, 2008, the Government ofCanada released “Turning the Corner — Taking Action to Fight Climate Change”(the “**Updated Action Plan**”) whichprovides some additional guidance with respect to the Government’s plan toreduce greenhouse gas emissions by 20 per cent by 2020 and by 60 per cent to 70per cent by 2050.

 

TheUpdated Action Plan is primarily directed towards industrial emissions fromcertain specified industries including the oil sands, oil and gas andrefining.  The Updated Action Plan isintended to create a carbon emissions trading market, including an offsetsystem, to provide incentive to reduce greenhouse gas emission and establish amarket price for carbon.  There are mandatoryreductions of 18 per cent from the 2006 baseline starting in 2010 and anadditional two per cent in subsequent years for existing facilities.  This target will be applied to regulatedsectors on a facility-specific, sector-wide or corporate basis; in the case ofoil sands production, petroleum refining, natural gas pipelines and upstreamoil and gas the target will be considered facility-specific (sectors in whichthe facilities are complex and diverse, or where emissions are affected byfactors beyond the control of the facility operator).  Emissions from new facilities, which arethose built between 2004 and 2011, will be based on a cleaner fuel standard toencourage continuous emissions intensity reductions over time, and will begranted a three-year grace period during which no emissions intensity targetswill apply.  Targets will begin to applyon the fourth year of commercial operation and the baseline will be the thirdyear’s emissions intensity, with a two per cent continuous annual emissionintensity improvement required.  Thedefinition of new facility also includes greenfield facilities, majorexpansions constituting more than a 25 per cent increase in a facility’sphysical capacity, as well as transformations to a facility that involvesignificant changes to its processes. For upstream oil and gas and natural gas pipelines, it will be appliedusing a sector-specific approach.  Forthe oil sands, its application will be process-specific, oil sands plants builtin 2012 and later, those which use heavier hydrocarbons, up-graders and *in-situ*production will have mandatorystandards in 2018 that will be based on carbon capture and storage.

 

Inthe following regulated sectors, the Updated Action Plan will apply only tofacilities exceeding a minimum annual emissions threshold: (i) 50,000tonnes of CO2 equivalent per year for natural gas pipelines;(ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facility;and (iii) 10,000 boe/d/company. These proposed thresholds are

 

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significantlystricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.

 

Fourseparate compliance mechanisms are provided in respect of the above targets:Technology Fund contributions, offset credits, clean development credits andcredits for early action.  The mostsignificant of these compliance mechanisms, at least initially, will be theTechnology Fund and for which regulated entities will be able to contribute in orderto comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 pertonne for the 2010-12 period, rising to $20 per tonne in 2013, and thereafterincreasing at the nominal rate of GDP growth. Contribution limits will correspondingly decline from 70 per cent in2010 to zero per cent in 2018.  Moniesraised through contributions to the Technology Fund will be used to invest intechnology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investingin large-scale and transformative projects at the same contribution rate andunder similar requirements as mentioned above.

 

Theoffset system is intended to encourage emissions reductions from activitiesoutside of the regulated sphere, allowing non-regulated entities to participatein and benefit from emissions reduction activities.  In order to generate offset credits, projectproponents must propose and receive approval for emissions reduction activitiesthat will be verified before offset credits will be issued to the projectproponent.  Those credits can then besold to regulated entities for use in compliance or non-regulated purchasersthat wish to either cancel the offset credits or bank them for future use orsale.

 

Underthe Updated Action Plan, regulated entities will also be able to purchasecredits created through the Clean Development Mechanism of the KyotoProtocol.  The purchase of such EmissionsReduction Credits will be restricted to 10 per cent of each firm’s regulatoryobligation, with the added restriction that credits generated through forestsink projects will not be available for use in complying with the Canadianregulations.

 

Finally,a one-time credit of up to 15 million tonnes worth of emissions credits will beawarded to regulated entities for emissions reduction activities undertakenbetween 1992 and 2006.  These creditswill be both tradable and bankable**.**

 

Giventhe evolving nature of the debate related to climate change and the control ofgreenhouse gases and resulting requirements, it is not currently possible topredict either the nature of those requirements or the impact on us and ouroperations and financial condition at this time.

 

**RISKFACTORS**

 

Thefollowing is a summary of certain risk factors relating to the business of theTrust and ARC Resources which prospective investors should carefully considerbefore deciding whether to purchase Trust Units or Exchangeable Shares.  Residents of the United States and othernon-residents of Canada should have additional regard to the risk factors underthe heading “Additional Risk Factors Applicable to Residents of the UnitedStates and Other Non-Residents of Canada”.

 

Weare a limited purpose trust and are entirely dependent upon the operations andassets of ARC Resources through our ownership, directly and indirectly, ofsecurities of ARC Resources, including the common shares of ARC Resources, theNotes and the Royalties.  Accordingly,our ability to pay distributions to Unitholders is dependent upon the abilityof ARC Resources to meet its interest, principal, dividend and otherdistribution obligations on the securities of ARC Resources and to pay theRoyalties.  ARC Resources’ income isreceived from the production of oil and natural gas from its Canadian resourceproperties and is susceptible to the risks and uncertainties associated withthe oil and natural gas industry generally. If the oil and natural gas reserves associated with ARC Resources’resource properties are not supplemented through additional development or theacquisition of additional oil and natural gas properties, the ability of ARCResources to meet its obligations to us and our ability to pay distributions toUnitholders may be adversely affected.

 

**Volatility of Oil and NaturalGas Prices**

 

Ouroperational results and financial condition, and therefore the amounts we payto Unitholders, will be dependent on the prices received for oil and naturalgas production. Oil and natural gas prices have recently declined

 

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precipitouslyand monthly distributions that reached a high point of $0.28 per Trust Unit in August of2008 declined to $0.15 per Trust Unit at December 31, 2008.  Current distributions are $0.12 per TrustUnit and continued low oil and natural gas prices or further declines in oiland natural gas prices will result in further declines in, or elimination of,such distributions.  Oil and natural gasprices are determined by economic factors and in the case of oil prices,political factors and a variety of additional factors beyond our control.  These factors include economic conditions, inthe United States and Canada, the actions of the Organization of PetroleumExporting Countries, governmental regulation, political stability in the MiddleEast and elsewhere, the foreign supply of oil and natural gas, risks of supplydisruption, the price of foreign imports and the availability of alternativefuel sources.  Any substantial andextended decline in the price of oil and natural gas would have an adverseeffect on the carrying value of our proved and probable reserves, borrowingcapacity, revenues, profitability and cash flows from operatingactivities.  Any movement in oil andnatural gas prices could have an effect on our financial condition and thereforeon the amounts to be distributed to our Unitholders.  We may manage the risk associated withchanges in commodity prices by entering into oil or natural gas pricehedges.  If we hedge our commodity priceexposure, we may forego some of the benefits we would otherwise experience ifcommodity prices were to increase.  Inaddition, commodity hedging activities could expose us to losses.  To the extent that we engage in risk managementactivities related to commodity prices, we will be subject to credit risksassociated with counterparties with which we contract.  For more information in relation to ourhedging program, see “Statement of Reserve Data and Other Oil and GasInformation– Other Oil and Gas Information– Forward Contracts”.

 

Volatileoil and gas prices make it difficult to estimate the value of producingproperties for acquisition and often cause disruption in the market for oil andgas producing properties, as buyers and sellers have difficulty agreeing onsuch value.  Price volatility also makes itdifficult to budget for and project the return on acquisitions and developmentand exploitation projects.  See “RiskFactors– Purchase of Properties” and “Risk Factors – Project Risks”.

 

**Variations in Interest Ratesand Foreign Exchange Rates**

 

Anincrease in interest rates could result in a significant increase in the amountwe pay to service debt, resulting in a decrease in distributions toUnitholders, and could impact the market price of the Trust Units.

 

Worldoil prices are quoted in Unites States dollars and the price received byCanadian producers is therefore affected by the Canadian/U.S. dollar exchangerate that may fluctuate over time.  Amaterial increase in the value of the Canadian dollar negatively impacts ourproduction revenue.

 

Overthe last two years, the Canadian dollar has experienced significant volatility,impacting the amount of Canadian dollars received by the Trust for itsproduction.  Continued volatility in theCanadian dollar may affect future distributions.  We may initiate certain hedges to attempt tomitigate the risk of the Canadian dollar appreciating against the U.S.dollar.  These hedging activities couldexpose us to losses.  To the extent thatwe engage in risk management activities related to foreign exchange rates andinterest rates, it will be subject to credit risk associated withcounterparties with which we contract. The increase in the exchange rate for the Canadian dollar and futureCanadian/United States exchange rates will impact future distributions and thefuture value of our reserves as determined by independent evaluators.

 

**Global Financial Crisis**

 

Recentmarket events and conditions, including disruptions in the international creditmarkets and other financial systems and the deterioration of global economicconditions, have caused significant volatility to commodity prices.  These conditions worsened in 2008 and arecontinuing in 2009, causing a loss of confidence in the broader U.S. and globalcredit and financial markets and resulting in the collapse of, and governmentintervention in, major banks, financial institutions and insurers and creatinga climate of greater volatility, less liquidity, widening of credit spreads, alack of price transparency, increased credit losses and tighter creditconditions.  Notwithstanding variousactions by governments, concerns about the general condition of the capitalmarkets, financial instruments, banks, investment banks, insurers and otherfinancial institutions caused the broader credit markets to further deteriorateand stock markets to decline substantially. These factors have negatively impacted company and trust valuations andwill impact the performance of the global economy going forward.

 

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Petroleumprices are expected to remain volatile for the near future as a result ofmarket uncertainties over the supply and demand of these commodities due to thecurrent state of the world economies, OPEC actions and the ongoing globalcredit and liquidity concerns.

 

**Refinancing Risk and DebtService**

 

Wecurrently have an $800 million syndicated credit facility with elevenbanks.  In normal circumstances,borrowers such as us rely on the fact that the banks will honour theircontractual commitments to fund draws as required.  In today’s economic environment there is arisk that one or more of the banks included in our syndicate may not honourdraws requested by us and thereby effect our ability to maintain our capitalexpenditure programs.  In the event thatthe facility is not extended before April 11, 2011, indebtedness under thefacility will be repayable at that date. There is also a risk that the credit facility will not be renewed forthe same amount or on the same terms. Variations in interest rates and scheduled principal repayments couldresult in significant changes in the amount required to be applied to debtservice before payment of the Royalties and interest on the Long Term Notes anddistributable income.  Furthermore, anyof these events could affect our ability to fund ongoing operations.

 

Wecurrently have U.S. $212 million of U.S. denominated long-term debt outstandingwhich requires principal repayments starting in April 2009 and continuinguntil December 2017.  We intend tofund these debt maturities with existing credit facilities.  In the event we are unable to refinance ourdebt obligations it may impact our ability to fund our ongoing operations anddistribute cash.

 

TheTrust is required to comply with covenants under the credit facility and underour U.S. denominated long-term notes.  Inthe event that we do not comply with covenants under the credit facility andour long term notes, our access to capital could be restricted or repaymentcould be required on an accelerated basis by our lenders, and the ability tomake distributions to our Unitholders may be restricted.  The lenders have security over substantiallyall of our assets.  If we become unableto pay our debt service charges or otherwise commit an event of default such asbreach of our financial covenants, the lender may foreclose on or sell ourworking interests in our properties.

 

At December 31,2008, we had approximately $296 million of unused credit available under ourbank credit facility. In addition, we have the ability to issue an additionalU.S. $113 million of long-term notes under an agreement with one lender.  This option, which will expire in May 2009unless it is renewed, would allow us to issue long-term notes at a rate equalto the related U.S. treasuries corresponding to the term of notes plus anappropriate credit spread adjustment at the time of issuance.  There is no assurance that this option willbe exercised or renewed.

 

Amountspaid in respect of interest and principal on debt may reducedistributions.  Variations in interestrates and scheduled principal repayments could result in significant changes inthe amount required to be applied to debt service before payment ofdistributions.  Certain covenants of theagreements with our lenders may also limit distributions.  Although we believe the credit facilitieswill be sufficient for our immediate requirements, there can be no assurancethat the amount will be adequate for our future financial obligations includingour capital expenditure program, or that additional funds will be able to beobtained.

 

Formore information, see “Other Information Relating to Our Business – Borrowing”.

 

**Capital Markets**

 

As aresult of the weakened global economic situation, the Trust along with allother oil and gas entities will have restricted access to capital and increasedborrowing costs.  Although our businessand asset base have not changed, the lending capacity of all financialinstitutions has diminished and risk premiums have increased.  As future capital expenditures will befinanced out of cash generated from operating activities, borrowings andpossible future equity sales, our ability to do so is dependent on, among otherfactors, the overall state of capital markets and investor appetite forinvestments in the energy industry and our securities in particular.

 

Tothe extent that external sources of capital become limited or unavailable oravailable on onerous terms, our ability to make capital investments andmaintain existing assets and reserves may be impaired, and our assets, liabilities,business, financial condition, results of operations and distributions may bematerially and adversely affected as a result.

 

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Alternatively,we may issue additional Trust Units from treasury at prices which may result ina decline in production per Trust Unit and reserves per Trust Unit or we maywish to borrow to finance significant acquisitions or development projects toaccomplish our long term objectives on less than optimal terms or in excess ofour optional capital structure.

 

Basedon current funds available and expected cash flow from operating activities, webelieve we have sufficient funds available to fund our projected capitalexpenditures.  However, if cash flow fromoperating activities is lower than expected or capital costs for these projectsexceed current estimates, or if we incur major unanticipated expenses relatedto development or maintenance of our existing properties, we may be required toseek additional capital to maintain our capital expenditures at plannedlevels.  Failure to obtain financingnecessary for our capital expenditure plans may result in a delay indevelopment or production on our properties or a decrease in distributions.

 

**Third Party Credit Risk**

 

Weare exposed to third party credit risk through our contractual arrangementswith our current or future joint venture partners, marketers of our petroleumand natural gas production and other parties. In the event such entities fail to meet their contractual obligations tous, such failures may have a material adverse effect on our business, financialcondition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venturepartners may impact a joint venture partner’s willingness to participate in ourongoing capital program, potentially delaying the program and the results ofsuch program until we find a suitable alternative partner.

 

**Maintenance of Distributions**

 

Weconduct limited exploration activities for oil and natural gas reserves.  Instead, we add to our oil and natural gasreserves primarily through development and acquisitions.  As a result, future oil and natural gasreserves are highly dependent on our success in exploiting existing propertiesand acquiring additional reserves.  Wealso distribute a significant proportion of our cash flow from operatingactivities to Unitholders rather than reinvesting it in reservesadditions.  Accordingly, if externalsources of capital, including the issuance of additional Trust Units, becomelimited or unavailable on commercially reasonable terms, our ability to makethe necessary capital investments to maintain or expand our oil and natural gasreserves may be impaired.  To the extentthat we use cash flow from operating activities to finance capital expendituresor property acquisitions, the level of cash flow from operating activitiesavailable for distribution to Unitholders will be reduced.  Additionally, we cannot guarantee that wewill be successful in developing additional reserves or acquiring additionalreserves on terms that meet our investment objectives.  Without these reserves additions, ourreserves will deplete and as a consequence, either production from, or the averagereserves life of, our properties will decline. These events may result in areduction in the value of Trust Units and in a reduction in cash flow fromoperating activities available for distributions to Unitholders.

 

**Regulatory**

 

Oiland natural gas operations (exploration, production, pricing, marketing andtransportation) are subject to extensive controls and regulations imposed byvarious levels of government, which may be amended from time to time.  Governments may regulate or intervene withrespect to price, taxes, royalties and the exportation of oil and naturalgas.  Such regulations may be changedfrom time to time in response to economic or political conditions.  There is no assurance that such changes will notbe materially adverse to our assets, reserves, financial condition or resultsof operations or prospects.  Theimplementation of new regulations or the modification of existing regulationsaffecting the oil and natural gas industry could reduce demand for natural gasand crude oil and increase our costs, any of which may have a material adverseeffect on our business, financial condition and results of operations.  In order to conduct oil and gas operations,we will require licenses from various governmental authorities.  There can be no assurance that we will beable to obtain all of the licenses and permits that may be required to conductoperations that we may wish to undertake. See “Industry Regulations”.

 

**Changes in Legislation**

 

Incometax laws, or other laws or government incentive programs relating to the oiland gas industry, such as the treatment of mutual fund trusts and resourcetaxation, may in the future be changed or interpreted in a manner thatadversely affects us and our Unitholders. Tax authorities having jurisdiction over us or Unitholders may disagree

 

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withhow we calculate our income for tax purposes or could change administrativepractises to our detriment or the detriment of Unitholders.

 

Weintend to continue to qualify as a mutual fund trust for purposes of the *Tax Act*. We may not, however, always be able to satisfy any future requirementsfor the maintenance of mutual fund trust status.  Should our status as a mutual fund trust belost or successfully challenged by a relevant tax authority, certain adverseconsequences may arise for us and Unitholders. Some of the significant consequences of losing mutual fund trust statusare as follows:

 

·                                        We wouldbe taxed on certain types of income distributed to Unitholders, includingincome generated by the Royalties held by us. Payment of this tax may have adverse consequences for some Unitholders,particularly Unitholders that are not residents of Canada and residents ofCanada that are otherwise exempt from Canadian income tax.

 

·                                        We wouldcease to be eligible for the capital gains refund mechanism available underCanadian tax laws if we cease to be a mutual fund trust.

 

·                                        TrustUnits held by Unitholders that are not residents of Canada would become taxableCanadian property.  These non-residentholders would be subject to Canadian income tax on any gains realized on adisposition of Trust Units held by them.

 

·                                        TrustUnits would not constitute qualified investments for registered retirementsavings plans (“**RRSPs**”),registered retirement income funds (“**RRIFs**”),registered education savings plans (“**RESPs**”)or deferred profit sharing plans (“**DPSPs**”).  If, at the end of any month, one of theseexempt plans holds Trust Units that are not qualified investments, the planmust pay a tax equal to one per cent of the fair market value of the TrustUnits at the time the Trust Units were acquired by the exempt plan.  An RRSP or RRIF holding non-qualified TrustUnits would be subject to taxation on income attributable to the Trust Units.  If an RESP holds non-qualified Trust Units,it may have its registration revoked by the Canada Revenue Agency.

 

Inaddition, we may take certain measures in the future to the extent we believenecessary to ensure that we maintain the status as a mutual fund trust.  These measures could be adverse to certainholders of Trust Units, particularly non-residents of Canada as defined in the *Tax Act*.

 

Theoil and natural gas industry is subject to extensive controls and regulationsgoverning its operations (including land tenure, exploration, development,production, refining, transportation, and marketing) imposed by legislationenacted by various levels of government and with respect to pricing andtaxation of oil and natural gas by agreements among the governments of Canada,Alberta, British Columbia, and Saskatchewan, all of which should be carefullyconsidered by investors in the oil and gas industry.  All of such controls, regulations andlegislation are subject to revocation, amendment or administrative change, someof which have historically been material and in some cases materially adverseand there can be no assurance that there will not be further revocation,amendment or administrative change which will be materially adverse to ourassets, reserves, financial condition or results of operations or prospects.

 

Formore information, see “Risk Factors – Non-resident Ownership of Trust Units”, “RiskFactors – Federal Tax Changes for Income Trusts and Corporations”, “RiskFactors – Environmental Concerns”, and “Industry Regulations – Environmental Regulation”.

 

**Reserves and ResourceEstimates**

 

Thereare numerous uncertainties inherent in estimating quantities of oil, naturalgas and natural gas liquids reserves and resources and the future revenue flowsattributed to such reserves, including many factors beyond our control.  In general, estimates of economicallyrecoverable oil and natural gas reserves and resources and the future netrevenues therefrom are based upon a number of variable factors and assumptions,such as historical production from the properties, production rates, ultimatereserve recovery, timing and amount of capital expenditures, marketability ofoil and natural gas, royalty rates, the assumed effects of regulation bygovernmental agencies and future operating costs, all of which may varymaterially from actual results.  Forthose reasons, estimates of the economically recoverable oil and natural gasreserves or estimates of resources attributable to any particular group ofproperties,

 

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classificationof such reserves based on risk of recovery and estimates of future net revenuesassociated with reserves prepared by different engineers, or by the sameengineers at different times, may vary.

 

Actualproduction and revenue flows derived from reserves will vary from the reservesestimates contained in the GLJ Report, and such variations could bematerial.  The estimates in the GLJReport are based in part on the timing and success of activities we intend toundertake in future years.  The reservesand estimated future net revenues to be derived therefrom contained in the GLJReport will be reduced in future years to the extent that such activities donot achieve the production performance set forth in the GLJ Report.

 

Thereserves and recovery information contained in the GLJ Report is only anestimate and the actual production and ultimate reserves from the propertiesmay be greater or less than the estimates prepared by GLJ.  The GLJ Report has been prepared usingcertain commodity price assumptions which are described in the notes to thereserves tables.  If we realize lowerprices for crude oil, natural gas liquids and natural gas and they aresubstituted for the price assumptions utilized in those reserves reports, thepresent value of estimated future net revenues for our reserves would bereduced and the reduction could be significant. In particular, we have experienced extreme volatility in the pricesreceived for oil and natural gas production and the difference between theforecast prices and costs reflected in the GLJ Report and our proceeds from thesale of our oil and natural gas could be materially lower.

 

**We have resource estimates of natural gas classified asDPIIP.  The resources estimates ofnatural gas are estimates only and the actual resources may be greater than orless than the estimates provided herein. A capital development project for the recovery of this volume of DPIIPcannot be defined at this time.  There isno certainty that it will be economically viable or technically feasible toproduce any portion of this natural gas classified as DPIIP.**

 

Estimatesof proved reserves that may be developed and produced in the future aresometimes based upon volumetric calculations and upon analogy to similar typesof reserves rather than actual production history.  Recovery factors and drainage areas wereestimated by experience and analogy to similar producing pools.  Estimates based on these methods are generallyless reliable than those based on actual production history.  Subsequent evaluation of the same reservesbased upon production history and production practices will result invariations in the estimated reserves and such variations could be material.

 

**Federal Tax Changes for IncomeTrusts and Corporations**

 

Newfederal legislation passed in June 2007, will apply a tax (“**SIFT tax**”) at the trust level ondistributions of certain income from trusts, such as the Trust, at rates of taxcomparable to the combined federal and provincial corporate tax and will treatsuch distributions as dividends to the Unitholders.  The SIFT tax results in adverse taxconsequences to the Trust and certain Unitholders (including most particularlyUnitholders that are tax deferred or non-residents of Canada) and may impactdistributions from the Trust.

 

Generally,there will be a transition period for an existing trust, such as the Trust, andthe tax under the new legislation will not apply until January 1, 2011.However, the new legislation provides that there are circumstances under whichan existing trust may lose its transitional relief before 2011, including wherethe “normal growth” of a trust existing on October 31, 2006 is exceeded.

 

Thenormal growth restrictions could adversely affect the cost of raising capitaland the Trust’s ability to undertake more significant acquisitions.   The SIFT tax substantially eliminates thecompetitive advantage that the Trust and other Canadian energy trusts enjoyedrelative to their corporate peers in raising capital in a tax-efficient manner,and makes the Trust Units less attractive as an acquisition currency. As aresult, it may become more difficult for the Trust to compete effectively foracquisition opportunities. There can be no assurance that the Trust will beable to reorganize its legal and tax structure to substantially mitigate theexpected impact of the SIFT tax.

 

Noassurance can be provided that the SIFT tax will not apply to us prior to January 1,2011, or that the legislation will not be further changed in a manner whichadversely affects us and our Unitholders. See “Risk Factors – Changes in Legislation”.

 

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** **

**Operational Matters**

** **

Acquiring, developing and exploring for oiland natural gas involves many risks, which even a combination of experience,knowledge and careful evaluation may not be able to overcome.  These risks include, but are not limited to,encountering unexpected formations or pressures, premature declines ofreservoirs, blow-outs, equipment failures and other accidents, sour gasreleases, uncontrollable flows of oil, natural gas or well fluids, adverseweather conditions, pollution, other environmental risks, fires andspills.  Although we maintain insurancein accordance with customary industry practice, we are not fully insuredagainst all of these risks.  Losses resultingfrom the occurrence of these risks could have a material adverse impact onus.  Like other oil and natural gastrusts and companies, we attempt to conduct our business and financial affairsso as to protect against political and economic risks applicable to operationsin the jurisdictions where we operate but there can be no assurance that wewill be successful in so protecting our assets.

 

In addition to the usual delays in paymentby purchasers of oil and natural gas to the operators of the properties, and bythe operator to us, payments between any of such parties may also be delayed byrestrictions imposed by lenders, delays in the sale or delivery of products,delays in the connection of wells to a gathering system, blowouts or otheraccidents, recovery by the operator of expenses incurred in the operation ofthe properties or the establishment by the operator of reserves forsuch expenses.

 

Continuing production from a property, andto some extent the marketing of production therefrom, are largely dependentupon the ability of the operator of the property.  Other companies operate some of theproperties in which we have an interest and as a result our returns on assetsoperated by others depends upon a number of factors outside our control.  Operating costs on most properties have increasedsteadily over recent years.  To theextent the operator fails to perform these functions properly, operating incomemay be reduced. Payments from production generally flow through the operatorand there is a risk of delay and additional expense in receiving such revenuesif the operator becomes insolvent.  Areduction of the income available for distributions could result in suchcircumstances.

 

Losses resulting from the occurrence of anyof these risks may have a material adverse effect on our business, financialcondition, results of operations and prospects.

 

**Allocations of Trust Income**

** **

The Trust Indenture provides that all ofthe distributable income of the Trust at the end of any calendar monthincluding December 31 shall be declared payable and distributed to theUnitholders of record on the last day of each such calendar month.  The distribution by the Trust of suchdistributable income is enforceable by such Unitholders of record.  However, if this amount is not determined anddeclared payable in accordance with the rules of the Toronto StockExchange, the right to receive this income will trade with the TrustUnits.  The Trust Indenture provides thatthis distributable income is allocated to Unitholders for tax purposes and tothe extent a Unitholder trades Trust Units in this period, they will beallocated such income but will have disposed of their right to receive suchdistribution.

 

In addition, the Trust Indenture providesthat such distributable income may be paid in whole or in part by cash, inTrust Units, or promissory notes payable in whole or in part in cash or TrustUnits on a specified date not more than 90 days after the record date to whichthe promissory note relates.  The TrustIndenture also provides for the consolidation of the Trust Units in thediscretion of the Board of Directors of ARC Resources to the pre-distributionnumber of Trust Units after any pro-rata distribution of additional Trust Unitsto all Unitholders.  Accordingly, theTrust Indenture allows for the payment of distributions in a form other thancash and Unitholders may have taxable income and cash taxes payable.

 

**Purchase of Properties**

** **

The price we pay for the purchase of theproperties is based on engineering and economic estimates of the reserves madeby independent engineers modified to reflect our technical and economic views.These assessments include a number of material assumptions regarding suchfactors as recoverability and marketability of oil, natural gas, natural gasliquids and sulphur, future prices of oil, natural gas, natural gas liquids andsulphur and operating costs, future capital expenditures and royalties andother government levies which will be imposed over the producing life of the 

 

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reserves. Many of these factors are subjectto change and are beyond our control and the control of the operators of theproperties.  In particular, changes inthe prices of and markets for petroleum, natural gas, natural gas liquids andsulphur from those anticipated at the time of making such assessments willaffect the amount of future distributions and as such the value of the TrustUnits. In addition, all such estimates involve a measure of geological andengineering uncertainty which could result in lower production and reservesthan attributed to the properties. Actual reserves could vary materially from these estimates.  Consequently, the reserves acquired may beless than expected, which could adversely impact cash flow from operatingactivities and distributions to Unitholders. See “ARC Energy Trust – General Development of the Business”.

 

**Enhanced Oil Recovery**

** **

We believe our ownership of assets inRedwater and North Pembina Cardium Unit #1 strategically positions us forparticipation in properties with large reserves of unrecovered originalresources in place which may be amenable to secondary recovery techniques suchas CO2 miscible or immiscibleflooding.  The implementation of enhancedoil recovery techniques on properties like Redwater or the North PembinaCardium Unit #1 are subject to significant risk factors, including therequirements of long term supply agreements for CO2 and large scale infrastructureinvestments.  We have just begun todevote resources to the study of such matters and no reserves are reflected inthe GLJ Report for any of these enhanced recovery techniques for the twosubject properties.  There is noassurance as to when or if such enhanced recovery techniques will beimplemented, or if implemented, when or if such enhanced recovery techniqueswould be successful.

 

Currently, companies are permitted to emitCO2 into the atmosphere with no requirement to capture and re-inject theemissions.  In order for ARC Resources tocarry out its enhanced oil recovery program it is necessary to obtain CO2 at a cost effective rate. Given that companies are not forced to capture their emissions, theinfrastructure has not been put in place to facilitate this process.  Under the current regulatory environment, theeconomic parameters of the Trust’s enhanced oil recovery programs would belimited.  For more information, see “RiskFactors – Environmental Concerns”.

 

**Project Risks**

** **

We manage a variety of small and largeprojects in the conduct of our business. Project delays may impact expected revenues from operations.  Significant project cost over-runs could makea project uneconomic.  Our ability toexecute projects and market oil and natural gas depends upon numerous factorsbeyond our control, including:

 

·              the availability of processingcapacity;

·              the availability and proximity ofpipeline capacity;

·              the availability of storagecapacity;

·              the supply of and demand for oiland natural gas;

·              the availability of alternativefuel sources;

·              the effects of inclement weather;

·              the availability of drilling andrelated equipment;

·              unexpected cost increases;

·              accidental events;

·              changes in regulations;

·              the availability and productivityof skilled labour; and

·              the regulation ofthe oil and natural gas industry by various levels of government andgovernmental agencies.

 

Because of these factors, we could beunable to execute projects on time, on budget or at all, and may not be able toeffectively market the oil and natural gas that we produce.

 

**Expansion of Operations**

** **

Our operations and expertise are currentlyfocused on oil and gas production and development in the Western CanadianSedimentary Basin.  In the future, we mayacquire oil and gas properties outside this geographic area.  In addition, the Trust Indenture does notlimit our activities to oil and gas production and development, and we couldacquire other energy related assets, such as oil and natural gas processingplants or pipelines, or an interest in an oil 

 

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sands project.  Expansion of our activities into new areasmay present new additional risks or alternatively, significantly increase theexposure to one or more of the present risk factors which may adversely affect ourfuture operational and financial conditions.

 

**Failure to Realize Anticipated Benefits ofAcquisitions and Dispositions**

** **

We make acquisitions and dispositions ofbusinesses and assets in the ordinary course of business.  Achieving the benefits of acquisitionsdepends in part on successfully consolidating functions and integratingoperations and procedures in a timely and efficient manner as well as ourability to realize the anticipated growth opportunities and synergies fromcombining the acquired businesses and operations with those of the Trust.  The integration of acquired business mayrequire substantial management effort, time and resources and may divertmanagement’s focus from other strategic opportunities and operationalmatters.  Management continually assessesthe value and contribution of services provided and assets required to providesuch services.  In this regard, non-coreassets are periodically disposed of, so that we can focus our efforts andresources more efficiently.  Depending onthe state of the market for such non-core assets, certain of our non-coreassets, if disposed of, could realize less than their carrying value on ourfinancial statements.

 

**Non-resident Ownership of Trust Units**

** **

The Trust intends to comply with therequirements under the *Tax Act*for “unit trusts” and “mutual fund trusts” at all relevant times such that wemaintain our status of a unit trust and a mutual fund trust for purposes of the*Tax Act*.  In this regard, we may, from time to time,among other things, take all necessary steps to monitor the activities of theTrust and ownership of the Trust Units. If at any time we become aware that the activities of the Trust andownership of the Trust Units by non-residents (non-residents of Canada and partnerships)may threaten the status of the Trust under the *TaxAct* as a “unit trust” or “mutual fund trust”, we are authorized totake such action as may be necessary in the opinion of ARC Resources tomaintain the status of the Trust as a unit trust and a mutual fund trust,including the imposition of restrictions on the issuance by the Trust, or thetransfer by any Unitholder, of Trust Units to a non resident. See “Limitationson Non-Resident Ownership” and “Risk Factors – Changes in Legislation”.

 

**Environmental Concerns**

** **

The oil and natural gas industry is subjectto environmental regulation pursuant to local, provincial and federallegislation.  A breach of suchlegislation may result in the imposition of fines or issuance of clean uporders in respect of us or our properties. Such legislation may be changed toimpose higher standards and potentially more costly obligations on us.  Furthermore, management believes thepolitical climate appears to favour new programs for environmental laws andregulation, particularly in relation to the reduction of emissions, and thereis no assurance that any such programs, laws or regulations, if proposed andenacted, will not contain emission reduction targets which we cannot meet, andfinancial penalties or charges could be incurred as a result of the failure tomeet such targets.  In particular thereis uncertainty regarding the Government of Canada’s *Clean Air Act*of 2006. The *Clean Air Act* proposesto reduce greenhouse gas emissions, however emission targets and compliancedeadlines differ from those outlined in the Kyoto Protocol which was ratifiedby Canada.  If passed, the *Clean Air Act* may have adverse operationaland financial implications to the Trust. See “Industry Regulations – Environmental Regulation”.  Although we have established a reclamationfund for the purpose of funding our currently estimated future environmentaland reclamation obligations based on our current knowledge, there can be noassurance that we will be able to satisfy our actual future environmental andreclamation obligations.

 

Provincial emission reduction requirements,such as those proposed in Alberta’s Bill 37 Climate Change and EmissionsManagement, may require the reduction of emissions or emissions intensity ofour operations and facilities.  Thedirect or indirect costs of these regulations may adversely and materiallyaffect our business.

 

Canada is a signatory to the United NationsFramework Convention on Climate Change and in December 2002 the Governmentof Canada ratified the Kyoto Protocol and it became legally binding on February 16,2005.  This protocol calls for Canada toreduce its greenhouse gas emissions to six per cent below 1990 levels duringthe period between 2008 and 2012.  Ourexploration and production facilities and other operations and activities emit greenhousegases that may subject us to legislation regulating emissions of greenhousegases.  The Government of Canada has putforward a Climate Change Plan for Canada which suggests further legislationwill set greenhouse gases emission reduction requirements for variousindustrial activities, including oil and gas exploration and production.

 

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On March 10, 2008, the Government ofCanada released “Turning the Corner – Taking Action to Fight Climate Change”(the “**Updated Action Plan**”) whichprovides some additional guidance with respect to the Government of Canada’splan to reduce greenhouse gas emissions by 20 per cent by 2020 and by 60 percent to 70 per cent by 2050.

 

There has been much public debate withrespect to the Government’s strategy or alternative strategies with respect toclimate change and the control of greenhouse gases.  Implementation of strategies for reducinggreenhouse gases whether to meet the limits required by the Kyoto Protocol or asotherwise determined, could have a material impact on the nature of oil andnatural gas operations, including ours. Given the evolving nature of the debate related to climate change andthe control of greenhouse gases and resulting requirements, it is not possibleto predict either the nature of those requirements or the impact on us and ouroperations and financial condition.  See “RiskFactors – Changes in Legislation”.

 

Although we believe that we are in materialcompliance with current applicable environmental regulations, no assurance canbe given that environmental laws will not result in a curtailment of productionor a material increase in the costs of production, development or explorationactivities or otherwise adversely affect our financial condition, results ofoperations or prospects.  Future changesin other environmental legislation could occur and result in stricter standardsand enforcement, larger fines and liability, and increased capital expendituresand operating costs, which could have a material adverse effect on ourfinancial condition or results of operations and prospects.  See “Industry Regulations– EnvironmentalRegulation”.

 

**Competition**

** **

There is strong competition relating to allaspects of the oil and gas industry. There are numerous trusts and corporations in the oil and gas industry,who are competing with us for the acquisitions of properties with longer lifereserves, properties with exploitation and development opportunities andundeveloped land.  As a result of suchcompetition, it may be more difficult for us to acquire reserves on beneficialterms.  Many of these other oil and gascompanies have significantly greater financial and other resources than we do.

 

The Trust competes with other oil and gasentities to hire and retain skilled personnel necessary for the dailyoperations of the Trust including the execution of the annual capitaldevelopment program.  The inability tohire and retain skilled personnel could adversely impact certain of ouroperational and financial results.

 

**Accounting Write-Downs as a Result of GAAP**

** **

Canadian Generally Accepted AccountingPrinciples (“**GAAP**”) require thatmanagement apply certain accounting policies and make certain estimates andassumptions which affect reported amounts in our consolidated financialstatements.  The accounting policies mayresult in non-cash charges to net income and write-downs of net assets in thefinancial statements. Such non-cash charges and write-downs may be viewed unfavourablyby the market and may result in an inability to borrow funds and/or may resultin a decline in the Trust Unit price.

 

Under GAAP, the net amounts at whichpetroleum and natural gas costs on a property or project basis are carried aresubject to a cost-recovery test which is based in part upon estimated futurenet revenues from reserves. If net capitalized costs exceed the estimatedrecoverable amounts, we will have to charge the amounts of the excess toearnings.  A decline in the net value ofoil and natural gas properties could cause capitalized costs to exceed the costceiling, resulting in a charge against earnings.  The net value of oil and gas properties arehighly dependent upon the prices of oil and natural gas.  See “Risk Factors - Volatility of Oil andNatural Gas Prices”.

 

Under US GAAP, companies using the fullcost method of accounting for oil and gas producing activities perform aceiling test on each cost centre using discounted estimated future net revenuefrom proved oil and gas reserves using a discount rate of 10 per cent.  Prices used in the US GAAP ceiling tests arethose in effect at year-end.  For theyear ended 2008, a ceiling test write-down of $1.15 billion was recorded for USGAAP purposes ($nil in 2007).  Theamounts recorded for depletion and depreciation have been adjusted in theperiods following similar additional write-downs taken under US GAAP in prioryears to reflect the impact of the reduction of delectable costs.  For further information, see Note 24 of ouraudited consolidated financial statements for the year ended December 31,2008 which is incorporated by reference in this Annual Information Form andwhich has been filed on SEDAR at www.sedar.com.

 

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On December 31, 2008, the SecuritiesExchange Commission published final rules and interpretations updating itsoil and gas reporting requirements.  Keyrevisions include changes to the pricing used to estimate reserves to utilize atwelve month average price, the ability to include non-traditional resources inreserves, the use of new technology for determining reserves, and permittingdisclosure of probable and possible reserves. The Securities Exchange Commission will require companies to comply withthe amended disclosure requirements for registration statements filed after January 1,2010, and for annual reports for fiscal years ending on or after December 15,2009.  Early adoption is notpermitted.  We are currently assessingthe impact of adoption in 2009; however, it is anticipated that the new requirementswill result in changes to our method of calculating the impairment test underUS GAAP.

 

GAAP requires that goodwill balances beassessed at least annually for impairment and that any permanent impairment becharged to net income. A permanent reduction in reserves, decline in commodityprices, and/or reduction in the Trust Unit price may indicate goodwillimpairment. As at December 31, 2008 we had $157.6 million recorded on ourbalance sheet as goodwill arising out of our acquisition of Star Oil &Gas Ltd. in 2003.  An impairment wouldresult in a write-down of the goodwill value and a non-cash charge against netincome. The calculation of impairment value is subject to management estimatesand assumptions.

 

Under GAAP, the accounting for derivativesmay result in non-cash charges against net income as a result of changes in thefair market value of derivative instruments. A decrease in the fair marketvalue of the derivative instruments as the result of fluctuations in commodityprices and foreign exchange rates may result in a write-down of net assets anda non-cash charge against net income. Such write-downs and non-cash charges maybe temporary in nature if the fair market value subsequently increases.

 

**Reliance on Key Members of Management**

** **

Our success depends in large measure oncertain key personnel.  The loss of suchkey personnel could delay the completion of certain projects or otherwise havea material adverse effect on us. Unitholders will be dependent on our management in respect of the administrationand management of all matters relating to our properties, the Royalties andTrust Units.  As of December 31,2008, we operated approximately 75 per cent of the total daily production ofour properties.  Investors who are notwilling to rely on our management should not invest in Trust Units.

 

**Depletion of Reserves**

** **

Distributions of distributable income inrespect of properties, absent commodity price increases or cost effectiveacquisition and development activities, will decline over time in a mannerconsistent with declining production from typical oil, natural gas and naturalgas liquids reserves.  We will not bereinvesting cash flow from operating activities in the same manner as otherindustry participants as we distribute significant amounts of our cash flow toUnitholders.  Accordingly, absent capitalinjections, our initial production levels and reserves may decline and thelevel of distributable income will be reduced.

 

Our future oil and natural gas reserves andproduction, and therefore our cash flows from operating activities, will behighly dependent on our success in exploiting our reserves base and acquiringadditional reserves. Without reserves additions through acquisition ordevelopment activities, our reserves and production may decline over time asreserves are produced.

 

There can be no assurance that we will besuccessful in developing or acquiring additional reserves on terms that meetour investment objectives.

 

**Net Asset Value**

** **

The net asset value of our assets from timeto time will vary dependent upon a number of factors beyond the control ofmanagement, including oil and gas prices. The trading prices of the Trust Units from time to time is alsodetermined by a number of factors which are beyond the control of managementand such trading prices may be greater than the net asset value of our assets.

 

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** **

**Return of Capital and Right of Redemption**

** **

Trust Units will have no value whenreserves from the properties can no longer be economically produced and, as aresult, distributions do not represent a “yield” in the traditional sense andare not comparable to bonds or other fixed yield securities, where investorsare entitled to a full return of the principal amount of debt on maturity inaddition to a return on investment through interest payments.  Distributions represent a blend of return ofUnitholders initial investment and a return on Unitholders initial investment.

 

Unitholders have a limited right to requirea repurchase of their Trust Units, which is referred to as a redemptionright.  See “Our Information – Rightof Redemption.”  It is anticipated thatthe redemption right will not be the primary mechanism for Unitholders toliquidate their investment.  The right toreceive cash in connection with a redemption is subject to materiallimitations.  Any securities which may bedistributed *in specie* toUnitholders in connection with a redemption may not be listed on any stockexchange and a market may not develop for such securities and such securitiesmay be illiquid.  In addition, there maybe resale restrictions imposed by law upon the recipients of the securitiespursuant to the redemption right.

 

**Nature of Trust Units**

** **

The Trust Units do not represent atraditional investment in the oil and natural gas sector and should not beviewed by investors as shares in ARC Resources. The Trust Units represent afractional interest in the Trust. Corporate law does not govern the Trust and the rights ofUnitholders.  As holders of Trust Units,Unitholders will not have the statutory rights normally associated withownership of shares of a corporation including, for example, the right to bringoppression or derivative actions.  Therights of Unitholders are specifically set forth in the Trust Indenture.  In addition, trusts are not defined asrecognized entities within the definitions of legislation such as the *Bankruptcy and Insolvency Act* (Canada),the *Companies’ Creditors Arrangement Act*(Canada) and in some cases the *Winding Upand Restructuring Act* (Canada). As a result, in the event of an insolvency or restructuring, aUnitholder’s position as such may be quite different than that of a shareholderof a corporation.  The Trust’s soleassets will be the royalty and other investments in securities. The price perTrust Unit is a function of anticipated distributable income, the propertiesacquired by us and our ability to effect long-term growth in our value.  The market price of the Trust Units will besensitive to a variety of market conditions including, but not limited to,interest rates and our ability to acquire suitable oil and natural gasproperties. Changes in market conditions may adversely affect the trading priceof the Trust Units.

 

**The Trust Units are not “deposits”within the meaning of the *Canada DepositInsurance Corporation Act* (Canada) and are not insured under theprovisions of that Act or any other legislation.  Furthermore, we are not a trust company and,accordingly, are not registered under any trust and loan company legislation aswe do not carry on or intend to carry on the business of a trust company.**

 

**Unitholder Limited Liability**

** **

The Trust Indenture provides that noUnitholder will be subject to any liability in connection with us or ourobligations and affairs and, in the event that a court determines Unitholdersare subject to any such liabilities, the liabilities will be enforceable onlyagainst, and will be satisfied only out of our assets. Pursuant to the TrustIndenture, we will indemnify and hold harmless each Unitholder from any costs,damages, liabilities, expenses, charges and losses suffered by a Unitholderresulting from or arising out of such Unitholder not having such limitedliability.

 

The Trust Indenture provides that allwritten instruments signed by or on behalf of the Trust must contain aprovision to the effect that such obligation will not be binding uponUnitholders personally. The principal investment of the Trust is the royaltyagreements which contain such provisions. Personal liability may also arise in respect of claims against the Trustthat do not arise under contracts, including claims in tort, claims for taxesand possibly certain other statutory liabilities.  The possibility of any personal liability ofthis nature arising is considered unlikely. The *Income Trusts Liability Act*(Alberta) came into force on July 1, 2004. The legislation provides that a Unitholder will not be, as abeneficiary, liable for any act, default, obligation or liability of thetrustee that arises after the legislation came into force.

 

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Our operations will be conducted, upon theadvice of counsel, in such a way and in such jurisdictions as to avoid as faras possible any material risk of liability on Unitholders for claims againstthe Trust.

 

**Title to Properties**

** **

Our properties are held in theform of licenses and leases and working interests in licenses and leases.  If we or the holder of the license or leasefails to meet the specific requirement of a license or lease, the license orlease may terminate or expire.  There canbe no assurance that any of the obligations required to maintain each licenseor lease will be met.  The termination orexpiration of a license or lease or the working interest relating to a licenseor lease may have a material adverse affect on our results of operations andbusiness.

 

Aboriginal peoples have claimed aboriginaltitle and rights to portions of western Canada. We are not aware that any material claims have been made in respect ofour properties and assets; however, if a claim arose and was successful thiscould have an adverse effect on us and our operations.

 

Although satisfactory title reviews aregenerally conducted in accordance with industry standards, such reviews do notguarantee or certify that a defect in the chain of title may not arise todefeat our claim to certain properties. In certain situations there may be multiple mineral resource ownersclaiming various ownership over the same parcel of land.  Any settlement of a dispute of ownership mayresult in the forfeiture of the mineral resource by us or the payment of cashcompensation to the mineral resource owner.

 

**Additional Risk FactorsApplicable to Residents of the United States and Other Non-Residents of Canada**

** **

***LimitedAbility of Residents in the United States to Enforce Civil Remedies***

*** ***

Both ARC and ARC Resources are organizedunder the laws of Alberta, Canada and have their principal place of business inCanada.  Most of our directors and all ofour officers and the representatives of the experts who provide services to us(such as our auditors and our independent reserve engineers), and all of ourassets and all or a substantial portion of the assets of such persons arelocated outside the United States.  As aresult, it may be difficult for investors in the United States to effectservice of process within the United States upon such directors, officers andrepresentatives of experts who are not residents of the United States or toenforce against them judgements of the United States courts based upon civilliability under the United States federal securities laws or the securitieslaws of any state within the United States. There is doubt as to the enforceability in Canada against ARC or ARCResources or against any of our directors, officers or representatives ofexperts who are not residents of the United States, in original actions or inactions for enforcement of judgements of United States courts of liabilitiesbased solely upon the United States federal securities laws or securities lawsof any state within the United States.

 

***Differencesin Reporting Practices in Canada and the United States***

*** ***

We report our production and reservequantities in accordance with Canadian practices and specifically in accordancewith NI 51-101.  These practices aredifferent from the practices used to report production and to estimate reservesin reports and other materials filed with the Securities Exchange Commission bycompanies in the United States.

 

We incorporate additional information withrespect to production and reserves which is either not generally included orprohibited under rules of the Securities Exchange Commission and practicesin the United States.  We follow theCanadian practice of reporting gross production and reserve volumes (beforededuction of Crown and other royalties); however, we also follow the UnitedStates practice of separately reporting reserve volumes on a net basis (afterthe deduction of royalties and similar payments).  We also follow the Canadian practice of usingforecast prices and costs when we estimate our reserves; whereas the SecuritiesExchange Commission requires that prices and costs be held constant at levelsin effect at the date of the reserve report. For additional information on reporting differences, see “Risk Factors –Accounting Write - Downs as a Result of GAAP”.

 

We included in this Annual Information Form estimatesof proved and proved plus probable reserves. Probable reserves are higher risk and are generally believed to be lesslikely to be accurately estimated or recovered than proved reserves. TheSecurities Exchange Commission generally prohibits the inclusion of estimatesof probable 

 

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reserves in filings made with it.  This prohibition does not apply to us becausewe are a Canadian foreign private issuer.

 

As a consequence of the foregoing, ourreserve estimates and production volumes in this Annual Information Form maynot be comparable to those made by companies utilizing United States reportingand disclosure standards.

 

***AdditionalTaxation Applicable to Non-Residents***

*** ***

The *TaxAct* and the tax treaties between Canada and other countries mayimpose additional withholding or other taxes on the distributions or otherproperty paid by us to Unitholders who are non-residents of Canada, and thesetaxes may change from time to time. Since January 1, 2005, a 15 per cent Canadian withholding tax isapplied to the return of capital portion of distributions made to non-residentUnitholders.

 

Additionally, the reduced “QualifiedDividend” rate of 15 per cent tax applied to our distributions under currentU.S. tax laws is scheduled to expire at the end of 2010 and there is noassurance that this reduced tax rate will be renewed by the U.S. government atsuch time.

 

Furthermore, it is anticipated that theimplementation of the SIFT tax may have tax consequences for non-residents ofCanada that are more adverse than the tax consequences to other classes ofUnitholders.

 

***ForeignExchange Risk of Non-Resident Unitholders***

*** ***

Our distributions are declared in Canadiandollars and converted to foreign denominated currencies at the spot exchangerate at the time of payment.  As aconsequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollarstrengthens with respect to their currency, the amount of the distribution willbe reduced when converted to their home currency.

 

**TRANSFER AGENTS AND REGISTRARS**

** **

The transfer agent and registrar for theTrust Units and the Exchangeable Shares is Computershare Trust Company ofCanada at its principal offices in Calgary and Toronto.

 

**MATERIAL CONTRACTS**

** **

The following comprises particulars ofevery material contract to the Trust that was entered into within the mostrecently completed financial year, or entered into before the most recentlycompleted financial year which is still in effect, other than a contractentered into in the ordinary course of business:

 

1.                                       Trust Indenture.  Forinformation, see “Our Information” and “Corporate Governance”.

 

2.                                       Exchangeable Share Provisions. For information, see “Share Capital of ARC Resources – ExchangeableShares”.

 

3.                                       Exchangeable Share Voting and Exchange Trust Agreement dated January 31,2001 among the trust, 908563 Alberta Ltd. (the predecessor to ARC Subco) ARCResources and Computershare Trust Company of Canada, as amended.  For information, see “Share Capital of ARCResources – Exchangeable Shares”.

 

4.                                       Exchangeable Share Support Agreement dated January 31, 2001among the trust, 908563 Alberta Ltd. (the predecessor to ARC Subco) ARCResources and Computershare Trust Company of Canada, as amended.  For information, see “Share Capital of ARCResources – Exchangeable Shares”.

 

5.                                       Amended and Restated Credit Agreement dated as of March 24,2006 between ARC Resources and a syndicate of lenders, and an administrativeagent as amended on March 30, 2007 for an extendible revolving creditfacility up to Cdn. $800 million.  Forinformation, see “Other Information Relating to Our Business - Borrowings”.

 

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6.                                       Amended and Restated Uncommitted Master Shelf Agreement as of December 15,2005 between ARC Resources and various purchasers for an aggregate principalamount of US $150 million.  Forinformation, see “Other Information Relating to Our Business - Borrowings”.

 

7.                                       Note Agreement as of April 27, 2004 between ARC Resources andvarious purchasers for US $62.5 million 4.62 per cent Senior Secured Notes – Series Adue April 27, 2014 and US $62.5 million 5.10 per cent Senior Secured Notes– Series B due April 27, 2016. For information, see “Other Information Relating to Our Business-Borrowings”.

 

Copies of each of these documents have beenfiled on SEDAR at www.sedar.com.

 

**INTEREST OF EXPERTS**

** **

There is no person or company whoseprofession or business gives authority to a statement made by such person orcompany and who is named as having prepared or certified a statement, report orvaluation described or included in a filing, or referred to in a filing, madeunder National Instrument 51-102 by us during, or related to, our most recentlycompleted financial year other than GLJ, our independent engineering evaluator,and Deloitte & Touche LLP, our auditors.  As at the date hereof the designatedprofessionals of GLJ Petroleum Consultants Ltd., as a group, beneficiallyowned, directly or indirectly, less than one per cent of our outstandingsecurities, including the securities of our associates and affiliates.  Deloitte & Touche LLP is the auditorof the Trust and is independent within the meaning of the Rules ofProfessional Conduct of the Institute of Chartered Accountants of Alberta.

 

In addition, none of the aforementionedpersons or companies, nor any director, officer or employee of any of theaforementioned persons or companies, is or is expected to be elected, appointedor employed as a director, officer or employee of ARC Resources or of any ofour associate or affiliate entities. Allan R. Twa, the Corporate Secretary of ARC Resources, is a partner of Burnet, Duckworth & Palmer LLP, which law firm renders legal services to us.

 

**ADDITIONAL INFORMATION**

** **

Additional information includingremuneration and indebtedness of directors and officers of ARC Resources,principal holders of the Trust Units, Exchangeable Shares and rights topurchase Trust Units, is contained in the Information Circular - ProxyStatement of the Trust which relates to the Annual Meeting of Unitholders to beheld on May 20, 2009.  Additionalfinancial information is provided in our consolidated financial statements andaccompanying management’s discussion and analysis for the year ended December 31,2008, which have been filed on SEDAR at www.sedar.com.

 

59

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**APPENDIX AFORM 51-101F2**

** **

**REPORT ONRESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR**

** **

Tothe board of directors of ARC Resources Ltd. (the “**Company**”) on behalf of ARC Energy Trust (the “**Trust**”):

 

1.             Wehave prepared an evaluation of the Company’s and other Trust’s subsidiaries’reserves data as at December 31, 2008. The reserves data are estimates of proved reserves and probable reservesand related future net revenues as at December 31, 2008 estimated usingforecast prices and costs.

 

2.             Thereserves data are the responsibility of the Company’s management.  Our responsibility is to express an opinionon the reserves data based on our evaluation.

 

Wecarried out our evaluation in accordance with standards set out in the CanadianOil and Gas Evaluation Handbook (the “**COGEHandbook**”) prepared jointly by the Society of Petroleum EvaluationEngineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &Petroleum (Petroleum Society).

 

3.             Those standards requirethat we plan and perform an evaluation to obtain reasonable assurance as towhether the reserves data are free of material misstatement.  An evaluation also includes assessing whetherthe reserves data are in accordance with principles and definitions presentedin the COGE Handbook.

 

4.             Thefollowing table sets forth the estimated future net revenue (before deductionof income taxes) attributed to proved plus probable reserves, estimated usingforecast prices and costs and calculated using a discount rate of 10 per cent,included in the reserves data of the Company evaluated by us for the year endedDecember 31, 2008, and identifies the respective portions thereof that wehave evaluated and reported on to the Company’s board of directors:

 
| **Independent  Qualified Reserves** | ** ** | **Description and  Preparation Date of** | ** ** | **Location of  Reserves (Country  or Foreign** | ** ** | **Net Present Value of Future Net Revenue  (before income taxes, 10% discount rate, millions dollars)** | ** ** |
|------------------------------------------|------------|---------------------------------------------------------|------------|---------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Evaluator**                            | ** ** | **Evaluation Report**                              | ** ** | **Geographic Area)**                                     | ** ** | **Audited**                                                                                                                                                              | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
| ** **                               | ** ** | ** **                                              | ** ** | ** **                                                    | ** ** | ** **                                                                                                                                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| GLJ  Petroleum Consultants Ltd.          |       | January 16,  2009                                  |       | Canada                                                        |       | —                                                                                                                                                                   |       | $ | 5,292 |   | — |   | $ | 5,292 |   |
|                                          |            |                                                         |            |                                                               |            |                                                                                                                                                                          |            |  |  |  |  |  |  |  |  |

 

5.             In our opinion, thereserves data respectively evaluated by us have, in all material respects, beendetermined and are in accordance with the COGE Handbook.

 

6.             Wehave no responsibility to update this evaluation for events and circumstancesoccurring after the preparation dates.

 

7.             Becausethe reserves data are based on judgments regarding future events, actualresults will vary and the variations may be material; however, any variationsshould be consistent with the fact that reserves are categorized according tothe probability of their recovery.

 

Executedas to our report referred to above:

 
| GLJ  Petroleum Consultants Ltd.         |     | Dated  February 19, 2009 |
|-----------------------------------------|----------|-------------------------------|
| Calgary,  Alberta, Canada               |     |                          |
|                                    |     |                          |
|                                    |     |                          |
| *(signed) “James H. Willmon”* | * * | * *                      |
| James H.  Willmon, P.Eng                |     |                          |
| Vice  President                         |     |                          |

 

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** **

**APPENDIX BFORM 51-101F3**

** **

**REPORT OFMANAGEMENT AND DIRECTORS ONRESERVES DATA AND OTHER INFORMATION**

** **

Managementof ARC Resources Ltd. (the “**Company**”)on behalf of ARC Energy Trust (the “**Trust**”)are responsible for the preparation and disclosure of information with respectto the Company’s and the other Trust’s subsidiaries’ oil and gas activities inaccordance with securities regulatory requirements. This information includesreserves data, which are estimates of proved reserves and probable reserves andrelated future net revenues as at December 31, 2008 estimated usingforecast prices and costs.

 

Anindependent qualified reserves evaluator has evaluated the Company’s and theother Trust’s subsidiaries’ reserves data. The report of the independentqualified reserves evaluator is presented below.

 

TheReserves Committee of the board of directors of the Company has

 

(a)           reviewedthe Company’s procedures for providing information to the independent qualifiedreserves evaluator;

 

(b)           metwith the independent qualified reserves evaluator to determine whether anyrestrictions affected the ability of the independent qualified reservesevaluator to report without reservation; and

 

(c)           reviewedthe reserves data with management and the independent qualified reservesevaluator.

 

TheReserves Committee of the board of directors has reviewed the Company’sprocedures for assembling and reporting other information associated with oiland gas activities and has reviewed that information with management. The boardof directors has, on the recommendation of the Reserves Committee, approved

 

(d)           thecontent and filing with securities regulatory authorities of Form 51-101F1containing reserves data and other oil and gas information;

 

(e)           thefiling of Form 51-101F2 which is the report of the independent qualifiedreserves evaluator on the reserves data; and

 

(f)            thecontent and filing of this report.

 

Becausethe reserves data are based on judgments regarding future events, actualresults will vary and the variations may be material.  However, any variations should be consistentwith the fact that reserves are categorized according to the probability oftheir recovery.

 
| (signed)  “*John P. Dielwart*”             |   | (signed)  “*Myron Stadnyk*”          |
|------------------------------------------------------|--------|------------------------------------------------|
| John  P. Dielwart                                    |   | Myron  Stadnyk                                 |
| Chief  Executive Officer                             |   | President  and Chief Operating Officer         |
|                                                 |   |                                           |
|                                                 |   |                                           |
| (signed)  “*James Houck*”                  |   | (signed)  “*Fred J. Dyment*”         |
| James  Houck                                         |   | Fred  J. Dyment                                |
| Director  and Chairman****of the Reserves  Committee |   | Director  and Member of the Reserves Committee |
|                                                 |   |                                           |
|                                                 |   |                                           |
| March 18,  2009                                 |   |                                           |

 

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** **

**APPENDIX C**

** **

**MANDATE OFTHE AUDIT COMMITTEE**

** **

**Roleand Objective**

** **

TheAudit Committee (the “Committee”) is a committee of the Board of Directors ofARC Resources Ltd. (“ARL”) to which the Board has delegated its responsibilityfor oversight of the nature and scope of the annual audit, management’sreporting on internal accounting standards and practices, financial informationand accounting systems and procedures, financial reporting and statements andrecommending, for Board of Director approval, the audited financial statementsand other mandatory disclosure releases containing financial information.  The objectives of the Committee, with respectto ARL and ARC Energy Trust (the “Trust”) (hereinafter collectively referred toas “ARC”), are as follows:

 

·              To assistDirectors to meet their responsibilities in respect of the preparation anddisclosure of the financial statements of ARC and related matters.

 

·              To provide bettercommunication between directors and external auditors.

 

·              To ensure theexternal auditors’ independence.

 

·              To increase thecredibility and objectivity of financial reports.

 

·              To strengthen therole of the outside directors by facilitating in depth discussions betweendirectors on the Committee, management and external auditors.

 

**Mandateand Responsibilities of Committee**

** **

·              It is theresponsibility of the Committee to satisfy itself on behalf of the Board withrespect to ARC’s internal control systems, including in particular relating toderivative instruments:

 

·              identifying, monitoring andmitigating business risks.

 

·              ensuring compliance withlegal and regulatory requirements.

 

·              It is a primaryresponsibility of the Committee to review the annual and quarterly financialstatements of ARC prior to their submission to the Board of Directors forapproval.  The process should include butnot be limited to:

 

·              reviewing changes inaccounting principles, or in their application, which may have a materialimpact on the current or future years’ financial statements;

 

·              reviewing significantaccruals, reserves or other estimates such as the ceiling test calculation;

 

·              reviewing accountingtreatment of unusual or non-recurring transactions;

 

·              reviewing the Trust’s statusas a “mutual fund trust” under the *IncomeTax Act* (Canada);

 

·              ascertaining compliance withcovenants under loan agreements and Trust Indenture;

 

·              reviewing financialreporting relating to asset retirement obligations;

 

·              reviewing disclosurerequirements for commitments and contingencies;

 

·              reviewing adjustments raisedby the external auditors, whether or not included in the financial statements;

 

·              reviewing unresolveddifferences between management and the external auditors;

 

·              obtain explanations ofsignificant variances with comparative reporting periods; and

 

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·              determine through inquiry ifthere are any related party transactions and ensure the nature and extent ofsuch transactions are properly disclosed.

 

·              The Committee isto review the financial statements and related information included inprospectuses, management discussion and analysis (MD&A), informationcircular-proxy statements and annual information forms (AIF), prior to Boardapproval.

 

·              With respect tothe appointment of external auditors by the Board, the Committee shall:

 

·              be directly responsible foroverseeing the work of the external auditors engaged for the purpose of issuingan auditors’ report or performing other audit, review or attest services forthe Trust, including the resolution of disagreements between management and theexternal auditor regarding financial reporting;

 

·              review management’srecommendation for the appointment of external auditors and recommend to theBoard appointment of external auditors and the compensation of the externalauditors;

 

·              review the terms ofengagement of the external auditors, including the appropriateness andreasonableness of the auditors’ fees;

 

·              when there is to be a changein auditors, review the issues related to the change and the information to beincluded in the required notice to securities regulators of such change; and

 

·              review and approve anynon-audit services to be provided by the external auditors’ firm and considerthe impact on the independence of the auditors.

 

·              Review withexternal auditors (and internal auditor if one is appointed by ARC) theirassessment of the internal controls of ARC, their written reports containingrecommendations for improvement, and management’s response and follow-up to anyidentified weaknesses.

 

·              The Committeeshall also review annually with the external auditors their plan for theiraudit and, upon completion of the audit, their reports upon the financialstatements of ARC and its subsidiaries.

 

·              Review all publicdisclosure containing audited or unaudited financial information beforerelease.

 

·              Review financialreporting relating to risk exposure.

 

·              Satisfy itself that adequate procedures arein place for the review of the Trust’s public disclosure of financialinformation from the Trust’s financial statements and periodically assess theadequacy of those procedures.

 

·              Establish procedures for:

 

·              the receipt, retention andtreatment of complaints received by the Trust regarding accounting, internalaccounting controls, or auditing matters; and

 

·              the confidential, anonymoussubmission by employees of the Trust of concerns regarding questionableaccounting or auditing matters.

 

·              Review andapprove ARC’s hiring policies regarding partners, employees and former partnersand employees of the present and external auditors of ARC.

 

·              Review any othermatters that the Audit Committee feels are important to its mandate or that theBoard chooses to delegate to it.

 

·              Undertakeannually a review of this mandate and make recommendations to the Policy andBoard Governance Committee as to proposed changes.

 

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** **

**Composition**

** **

·              This Committeeshall be composed of at least three individuals appointed by the Board fromamongst its members, all of which members will be independent (within themeaning of Multilateral Instrument 52-110 Audit Committees) unless the Boarddetermines to rely on an exemption in NI 52-110.  “Independent” generally means free from anybusiness or other direct or indirect material relationship with ARC that could,in the view of the Board of Directors, reasonably interfere with the exerciseof the member’s independent judgment.

 

·              The Secretary tothe Board shall act as Secretary of the Committee.

 

·              A quorum shall bea majority of the members of the Committee.

 

·              All of themembers must be financially literate within the meaning of NI 52-110 unless theBoard has determined to rely on an exemption in NI 52-110.  Being “financially literate” means membershave the ability to read and understand a set of financial statements thatpresent a breadth and level of complexity of accounting issues that aregenerally comparable to the breadth and complexity of issues that canreasonably be expected to be raised by the Trust’s financial statements.

 

**Meetings**

** **

·              The Committeeshall meet at least four times per year and/or as deemed appropriate by theCommittee Chair.

 

·              The Committeeshall meet not less than quarterly with the auditors, independent of thepresence of management.

 

·              Agendas, withinput from management, shall be circulated to Committee members and relevantmanagement personnel along with background information on a timely basis priorto the Committee meetings.

 

·              Minutes of eachmeeting shall be prepared by the Secretary to the Committee.

 

·              The ChiefExecutive Officer and the Chief Financial Officer or their designates shall beavailable to attend at all meetings of the Committee upon the invitation of theCommittee.

 

·              The Controller,Treasurer and such other staff as appropriate to provide information to theCommittee shall attend meetings upon invitation by the Committee.

 

**Reporting/ Authority**

** **

·              Following eachmeeting, in addition to a verbal report, the Committee will report to the Boardby way of providing copies of the minutes of such Committee meeting at the nextBoard meeting after a meeting is held (these may still be in draft form).

 

·              Supportingschedules and information reviewed by the Committee shall be available forexamination by any director.

 

·              The Committeeshall have the authority to investigate any financial activity of theCorporation and to communicate directly with the internal and externalauditors.  All employees are to cooperateas requested by the Committee.

 

·              The Committee may retain, andset and pay the compensation for, persons having special expertise and/orobtain independent professional advice to assist in fulfilling its duties andresponsibilities at the expense of ARC.

 

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